Wireline Basic

Index

1 FACILITY SAFETY

1.1 RULES AND REGULATIONS

1.1.1 Classroom House Rules

1.1.2 Workshop and Well Site Rules

1.1.3 Course Rules

1.1.4 Fire Plan

2 ORIGINS OF OIL AND GAS

2.1 INTRODUCTION

2.2 COMMERCIAL OIL FIELDS

2.3 RESERVIOR DRIVE MECHANISMS

2.3.1 Internal Drive

2.3.2 Depletion Drive

2.3.3 External Gas Cap

2.3.4 Water Drive

2.3.5 External Drive

3 COMPLETION DESIGN

3.1 INTRODUCTION

3.2 WIRELINE RE-ENTRY GUIDE

3.3 TUBING PROTECTION JOINT

3.4 NO-GO LANDING NIPPLE

3.5 PERFORATED PUP JOINT

3.6 LANDING NIPPLE

3.7 PUP JOINT

3.8 CROSSOVER

3.9 MILLOUT EXTENSION

3.10 PACKER

3.11 POLISHED BORE RECEPTACLE (PBR)

3.12 TUBING LANDING NIPPLE

3.13 SIDE POCK MANDREL

3.14 MID-TUBING LANDING NIPPLE

3.15 FLOW COUPLING

3.16 SAFETY VALVE LANDING NIPPLE

3.17 TUBING

3.18 CONTROL LINE

3.19 TUBING HANGER

Wireline Basic

4 XMAS TREES

4.1 INTRODUCTION

4.2 VALVES

4.2.1 Lower Master Valve (LMV)

4.2.2 Upper Master Valve (UMV)

4.2.3 Flow Wing Valve (FWV)

4.2.4 Kill Wing Valve (KWV)

4.2.5 Choke Valve

4.2.6 Swab Valve

4.2.7 Tree Cap

5 WHAT IS WIRELINE?

5.1 INTRODUCTION

5.2 BENDING STRESSES

5.3 RE-SPOOLING

5.4 HANDLING AND STORAGE

5.5 GENERAL SAFETY PRECAUTIONS

5.6 WIRELINE TORSION TESTER

5.6.1 Objective

5.6.2 Procedure

5.6.3 Slickline Operation And Maintenance

5.6.4 Torsion Test Specimen Configuration

5.7 WIRELINE TEST ANALYSIS

5.7.1 Acceptance

5.7.2 Torsion Fracture Analysis

5.7.3 Fracture Classification

5.7.4 General Guidance Notes

Wireline Basic

6 QUICK UNIONS

6.1 INTRODUCTION

6.1.1 Wellhead Adaptor (Tree Adaptor)

6.1.2 Pump-In Tee

6.1.3 Wireline Blow Out Preventor (BOP)

6.1.4 Pressure Testing of BOP

6.1.5 Lubricators

6.1.6 Injection Sub

6.1.7 Cutter Valve

6.1.8 Workover Valve

6.1.9 Stuffing Box

6.1.10 Hydraulic Packing Nut

7 WIRELINE UNIT

7.1 HAY PULLEY AND WEIGHT INDICATOR

7.2 HAY PULLEY

7.3 WEIGHT INDICATOR

7.3.1 Introduction

7.4 COUNTER HEAD

7.5 CAUSES FOR DEPTH DISCREPANCIES

7.5.1 Wireline Angle Correction Factors

7.6 WIRELINE CLAMP

8 POWER PACKS

8.1 ELECTRICAL

8.2 DIESEL

8.2.1 Fault Finding Chart

9 WELL CONTROL PANEL AND B.O.P PUMPS

9.1 WELL CONTROL PANEL

9.2 OPERATING PROCEDURES

9.2.1 Pre-Operational Checks

9.2.2 Routine Operating Procedures

Wireline Basic

10 GENERAL TOOLSTRING

10.1 PRIMARY EQUIPMENT

10.1.1 Rope Sockets

10.1.2 Stem Types

10.1.3 Knuckle Joints

10.1.4 Power Jars

10.1.5 Mechanical Jars

10.1.6 Accelerators/ Stretch Simulators

10.1.7 Quick Lock System

11 NON-SETTING WIRELINE TOOLS

13.1 GAUGE CUTTER

13.2 LEAD IMPRESSION BLOCK

13.3 BLIND BOX

13.4 TUBING END LOCATOR

13.5 BAILERS

13.5.1 Pump Bailer

13.5.2 Drive Down Bailer

13.5.3 Hydrostatic Bailer

12 BASIC PULLING TOOLS

12.1 FISHING NECK IDENTIFICATION / EXTERNAL / INTERNAL

REACH

12.1.1 Selection of Shear Direction

12.2 BASIC PULLING TOOLS

12.2.1 ‘S’ Series Pulling Tool (Shear Down To Release)

12.2.2 ‘R’ Series Pulling Tool (Shear Up To Release)

12.2.3 ‘JD’ Series Pulling Tool (Shear Down To Release)

12.2.4 ‘JU’ Series Pulling Tool (Shear Up To Release)

12.2.5 ‘GS’ Series Pulling Tool (Shear Down To Release)

12.2.6 ‘GR’ Series Pulling Tool (Shear Up To Release)

12.2.7 ‘PRS’ Series Pulling Tool (Shear Down To Release)

13 EXERCISES

13.1 WIRELINE PROGAMME

13.1.1 Wireline PCE and toolstring preparation

13.1.2 Programme Objectives

13.1.3 Programme Execution

13.1.4 Lessons Learned

1 FACILITY SAFETY

1.1 RULES AND REGULATIONS

1.1.1 Classroom House Rules

a) Starting time will be 09:00 and finishing time 16:30, Monday through Friday.

• Coffee Breaks - 15 minutes in the morning.

- 15 minutes in the afternoon, depending on workload.

• Lunch break will be 30 minutes or at the instructor's discretion.

b) All materials, handouts etc. will be collected and left tidy on your desk at the end of

each day.

• Empty coffee cups and rubbish must be disposed in the bins provided.

c) A sensible dress code will be expected while working in the classroom.

1.1.2 Workshop Or Well Site Rules

a) Lockers

Lockers will be provided for all students during the course. The locker will be your

personal responsibility and kept clean and tidy. Also keep the changing room tidy.

b) Wellsite

We must assume the work area is a pipe deck offshore and respect it the same manner.

• All equipment must be rigged up and laid out neatly.

• All oil or diesel spillage must be mopped up immediately using the oil spill

granules or cleaning fluids provided.

• After rigging down the unit, the workbench and tools must be cleaned and

returned to the appropriate storage place and left as you would expect to find it.

c) All downhole tools used will be stripped, cleaned and redressed, if necessary, ready

for the next class.

d) When outside on the Training Well you will always wear the following:

• Hard Hat

• Safety Boots

• Coveralls

• Safety Glasses

• Gloves

• Hearing Protection as required

e) Equipment operating signals

There are a number of signals that must be learnt know in order to acknowledge proper

functioning and movement of the wireline equipment. These signals will be demonstrated

to you and must be used at all times when working with the wireline unit.

f) Safety harness

As offshore, all students must wear a safety harness while working any more than 1.5

metres off the ground.

• While rigging the equipment up or down these safety harnesses will be

provided and will be used.

1.1.3 Course Rules

1) Personnel safety is paramount. Always wear Personal Protective Equipment (PPE)

when working outside, in the workshop or wellhead areas.

2) Report all accidents or incidents to your instructor, no matter how trivial they may

seem at the time. Seek medical aid if required. If accidents are not reported,

appropriate actions cannot be implemented to prevent similar future occurrences.

3) No alcohol is to be consumed in the training centre, unless authorised for special non-

training occasions. Any student found under the influence of alcohol will be

immediately expelled from the class and reported to his immediate line manager.

4) Full effort by students is expected on all courses.

5) Random alcohol and/or substance abuse test may be carried out during the term of

the course.

6) PPE and dirty clothes/shoes shall not be worn inside the building i.e. classroom,

recreation area, office, etc.

7) As you are not the only students using the facility, please show respect for others.

No foul language and no obscene materials are allowed.

8) Good housekeeping is required everywhere, including the locker facilities and toilets.

9) You are expected to be in class by 09.00 am each day and you will be allowed coffee

and lunch breaks at the set times. Your course instructor will advise you of these

times.

10) The course register must be filled in each day. The register keeper should deliver it

to the training secretary by 08.45 am.

11) PSL Energy Services operate a no smoking policy within the training centre, however

a designated smoking area is provided for delegates.

SIGNED DATE

2 ORIGINS OF OIL AND GAS

2.1 INTRODUCTION

Petroleum (derived from the Greek ‘Petra’ for rock and the Latin ‘Oleum’ for oil) is

obtained from the fluids contained in underground reservoirs.

The hydrocarbons contained in these fluids have had their origins in the residues of plant

and animal life, which were washed into sedimentary basins and buried through time.

Subjected to abnormal temperature and pressure gradients, the fats and proteins in these

residues are probably decomposed aerobically (without oxygen) in the source rock to form

the hydrocarbons known generically as gas, condensate, or black oil.

The formation of these hydrocarbons is invariably accompanied by volume changes with

high increases in local pressure. These pressure increases probably initiate micro fractures

in the sedimentary rock, thereby allowing the hydrocarbons to migrate along potential

gradients until they surfaced, or were caught in traps.

Most traps are structural anticline or fault traps, which are common to the majority of

sedimentary basins. Three-dimensional containment is established by an impermeable seal

above, around the sides, and by the buoyancy of the hydrocarbons on underlying water.

This section contains a discussion of the Organic Theory of Petroleum, which is the widely

accepted version by the scientific world, with a brief overview of geological structures

which form petroleum reservoirs.

2.2 COMMERCIAL OIL FIELDS

In order for an oil and gas field to exist, four basic conditions must have been met:

• A source from which hydrocarbons originated, with suitable environmental

conditions that changed the source material into petroleum

• A porous rock bed laid down, through which the petroleum could migrate to its

reservoir rock.

• A suitably shaped trap formed under which the petroleum accumulated

• An impervious cap or seal rock overlaid causing the trap.

To ensure that a field is commercially viable, the reservoir rock must in addition exhibit

three further essential characteristics:

• Continuity between pore spaces or permeability. There must be some degree of

continuity between void spaces so that reservoir fluids can flow through long

distances under very small pressure gradients

• Hydrocarbons must be of low enough molecular weight and, therefore,

viscosity to allow flow to occur.

• Must have an organic content greater than 1% (the organic content of typical

North Sea hydrocarbon-bearing rock exceeds 7%).

2.3 RESERVOIR DRIVE MECHANISMS

Ideally in an offshore oil field, the hydrocarbons are recovered from the reservoir pore

spaces by exploiting a drive mechanism, precluding the need for artificial methods. Drive

mechanisms have two classifications:

• Internal drive using the internal energy of the reservoir configuration

• External drive, which involves the invasion of the pore spaces by a replacement

fluid.

2.3.1 Internal Drive

This is known as primary recovery, which includes three drive mechanisms:

• Depletion or internal gas drive.

• External gas cap drive.

• Water drive.

2.3.2 Depletion Drive

The compressibility of oil and water is relatively small. As soon as production commences,

it is accompanied by a rapid drop of pressure in the producing zone which soon reaches the

bubble point of entrained gas. See Error! Reference source not found. Initially, this gas

is dispersed, but it rapidly expands and assists in dispelling the oil. Eventually, however,

the gas will start to form a gas front, which, having more mobility than the oil, and

increases the production gas/oil ratios. This depletion or internal gas drive is characterised

by a rapid decline in reservoir pressure and by the recovery of only a small percentage of

the oil in situation of 5 to 20 % maximum.

2.3.3 External Gas Cap

Where the oil has a gas cap, the gas cap pressure together with the pressure of gas in

solution tends to maintain pressure in the reservoir much longer than depletion drive. See

Error! Reference source not found.. Therefore gas cap reservoirs have higher recovery

rates of (20 to 40%).

2.3.4 Water Drive

Water drive is characterised by large local deposits of water which expand as pressure is

reduced in the reservoir see Error! Reference source not found.. Eventually, recovery

will decrease due to the greater mobility of the water front which eventually breaks through

to the wellbore with increasing water/oil ratios. Nonetheless, water drive is the most

efficient of the drive mechanisms and can produce recovery rates as high as 60 %.

All three drive mechanisms may be present to varying degrees at the same time although

one will be predominant.

2.3.5 External Drive

If a fluid is injected into a well so that the volumetric rate of fluid replacement is equal to

the volumetric rate of fluid extraction, then the average reservoir pressure will tend to

remain constant. Injection stimulates secondary recovery.

Depending on the type and configuration of the reservoir, pressure can be maintained

therefore by:

• Gas injection

• Water injection

• Miscible and immiscible fluid injection.

In general, gas is injected into the crest, and water injection into the base or periphery of

the reservoir. Particular consideration must be given to the quality of the injection fluids,

compatible with existing reservoir fluids, filtered to prevent formation plugging, viscose

which should be significantly higher than formation water, variations in reservoir

permeability, and injection rate. If the injection rate is excessive, the water front may

advance unevenly, thus giving rise to early water breakthrough, or to unstable coning

3 COMPLETION DESIGN

3.1 INTRODUCTION

The example completion selected (refer to Error! Reference source not found.), is an

example of a simple and versatile design.

The equipment used in this completion is in common use and the specific applications and

uses are outlined in the sub-sections below.

Starting with item 25, on the completion schematic (which is the first item to be run in the

hole), there follows a brief description of the use and position of each item of equipment in

the string.

3.2 WIRELINE RE-ENTRY GUIDE

(Refer to Item 25 on the diagram.)

This guide, sometimes abbreviated to WEG, is generally available in two forms.

g) Bell Guide

This guide has a 45° lead-in taper to allow easy re-entry of wireline tools into the tubing

strings. This guide is used in a completion where the end of the tubing does not need to

enter the top of liner hanger or packer tops.

h) Mule Shoe Re-Entry

This guide is essentially the same as a bell guide, but modified by having a large 45° angle

cut across from the outside of the guide. The 45° shoulder when orientated by turning the

tubing enables the guide to enter liner tops.

3.3 TUBING PROTECTION JOINT

(Item 24)

This is a single joint of tubing, included for the particular purpose of protecting

pressure/temperature gauges that may be suspended from the landing nipple immediately

above.

3.4 NO-GO LANDING NIPPLE

(Item 23)

This nipple is used exclusively for the installation of wireline set gauge hangers.

Figure 3.1 - Typical Completion Schematic

3.5 PERFORATED PUP JOINT

(Item 22)

In wells having large flow volumes, a restriction in the tubing such as a gauge hanger, will

cause false pressure recordings. Vibration due to flow turbulence may also cause extensive

damage to the gauges, therefore a perforated pup joint (approx. 10 ft long) is installed

above the gauge hanger nipple. This allows flow to pass unrestricted around the gauges and

hanger, providing accurate pressure/temperature recordings within the limits of the gauge..

The total area of the perforations must be greater than the ID of the pup joint (generally 3-4

times the area).

3.6 LANDING NIPPLE

(Item 21)

This nipple is the primary plugging point below the packer, it is used during the initial

completion stage as a receptacle for a ‘test tool’. A test tool is run into a no-go nipple and

seats against the no-go shoulder, it does not lock into the nipple. The test tool packings

create a seal within the seal bore of the nipple and will hold pressure from above only. It

should hold sufficient pressure to enable the setting of the hydraulic packer, and then test

the tubing.

After its initial use as described above, the nipple is used for well plugging by installing the

appropriate type plug (e.g. when tubing above the packer has to be pulled leaving the

packer in the hole).

3.7 PUP JOINT

(Item 20)

Used for spacing out tubing or as a handling joint when completion equipment is made up

into sub-assemblies for ease of handling and quick completion installation.

3.8 CROSSOVER

(Item 19)

A crossover is a connector which fits between two different sizes or types of threaded

connections. For instance between 4 ½” to 5 ½” or 3 ½” to 4 ½” tubing, etc.

3.9 MILLOUT EXTENSION

(Item 18)

This is generally a pup joint with a slightly larger ID than the packer bore and provides a

shoulder onto which a packer-plucker can latch during packing/milling operations. This

enables the packer and tail-pipe assembly to be retrieved during the same run as the milling

operation.

3.10 PACKER

(Item 17)

The packer in the example is a hydraulic type set permanent packer, which is installed on

the production string. It isolates the producing zone from the tubing/casing annulus. This

protects the production casing from well pressure and corrosive fluids maintaining its

integrity over the life of the well.

3.11 POLISHED BORE RECEPTACLE (PBR)

(Item 16)

The seal receptacle is attached to the top of the packer. The seal assembly, which mates

with the PBR, is attached to the bottom of the tubing string.

The function of the PBR is to allow travel upwards and downwards within the PBR to cater

for tubing movement due to expansion or contraction of the tubing caused by flowing

conditions or well operations.

Sometimes the seals are attached to the PBR with shear-pins or shear-ring in order that the

completion can be installed in one trip. The shear pins or shear ring can then be

hydraulically or mechanically sheared to allow travel, after the packer has been set.

3.12 TUBING LANDING NIPPLE

(Item 15)

This nipple is used for testing the tubing above the packer. In conjunction with item 21, it

can be used to find if tubing leaks are present above or below the packer.

3.13 SIDE POCKET MANDREL

(With Shear Relief Valve)

(Item 14)

This can be used as an alternative circulating device to a conventional sliding side door

*(SSD), which can incorporate an annulus pressure actuated circulating valve. The valve is

operated by applying pressure to the annulus which is the annular space between the tubing

OD and the production casing ID.

* The SSD is a circulating device to provide a means of communication between the

tubing and annulus. SSD’s are operated by shifting a sleeve to align communication

ports. This is done be means of a wireline run tool.

MID-TUBING LANDING NIPPLE

(Item 10)

This landing nipple would is installed at approx. 3,500 ft and would normally be used for

plugging the well if a neighbouring well is being drilled in the immediate vicinity and is to

be ‘kicked off’ or deviated. The kick-off point for deviated wells in the North Sea is

generally around 2000 ft. If, in the unlikely event, the drill-bit should penetrate the well,

the reservoir pressure would be isolated from reaching the drill string by the plug in the

nipple.

3.14 FLOW COUPLING

(Item 9)

When flowing a high rate well, the fluid will move at extremely high speed. When meeting

a restriction, such as a nipple profile, excessive turbulence will develop immediately above

the nipple causing excessive erosion. To cater for this excessive erosion, a six foot joint of

heavy walled tubing would be installed above (and sometimes below) the nipple. Although

the same amount of erosion will be experienced, the added wall thickness of the flow

coupling will leave sufficient material intact to prevent any leakage during the life of the

well.

3.15 SAFETY VALVE WIRELINE NIPPLE

(Item 5)

This nipple is designed to accommodate a wireline retrievable safety valve, remotely

operated from the surface by a hydraulic control line,

• (Item 4) - See Item 9

• (Item 3) - See Item 20

The other common type of safety valve used is the tubing retrievable type safety valve.

This valve is installed as a component of the tubing string and also requires a control line

for operation from surface.

3.16 TUBING

(Item 2)

Tubing is the flow conduit for the produced fluids. It is manufactured in lengths, termed

joints, of approximately 30 to 35 feet long.

The tubing connects all of the other completion components together from the re-entry

guide to surface.

3.17 CONTROL LINE

(Item 1)

This is normally a 1/4 inch OD Monel or stainless steel tubing, connected between the

safety valve nipple (or tubing retrievable valve) and the tubing hanger. The control line is

secured to the tubing by clamps (these may be Steel or Plastic). It is the conduit used for

the supply of hydraulic pressure from the surface control panel to the safety valve.

3.18 TUBING HANGER

The tubing hanger (not shown) supports the weight of the completion string in the wellhead

and also seals between the tubing/Xmas tree bore and the annulus.

4 XMAS TREES

4.1 INTRODUCTION

A Xmas tree is an assembly of valves and fittings used to control the flow of wellfluids at

surface and to provide access to the production tubing. The Xmas tree is essentially a

manifold of valves which is installed as a unit on top of a tubing head upper flange, or

adapter flange, of a wellhead; Figure 4.1.

4.2 VALVES

Typically, from bottom to top, a Xmas tree will contain the following valves:

4.2.1 Lower Master Valve (LMV)

• Application:- Utilised in all Xmas trees to close in the well

• Operation:- Manual.

The master valve, as its name implies, is the most important valve on the Xmas tree. When

closed this valve contains well pressure and should only be used for safety and isolation

purposes and never should be used as a working valve.

In moderate to high pressure wells, Xmas trees are often provided with two master valves,

the upper of which is furnished with a valve actuator system for automatic or remote

controlled operation (surface safety valve). This is often a regulatory requirement in sour or

high pressure wells.

4.2.2 Upper Master Valve (UMV)

• Application:- Utilised on moderate to high pressure wells as an emergency

shut in system. The valve is sometimes capable of cutting 7/32 inch braided

wireline.

• Operation:- Valve actuated pneumatically or hydraulically.

The UMV is a surface safety valve and is normally connected to the emergency shutdown

(ESD) system.

4.2.3 Flow Wing Valve (FWV)

• Application:- To permit the passage of well fluids to the choke valve.

• Operation:- Manual or automatic (pneumatic/hydraulic) depending on

whether the surface safety system includes the production wing.

On moderate to high pressure wells, two production wing valves are installed, one manual

and the other equipped with a valve actuator.

Figure 4.1 - Xmas Tree Valve System

4.2.4 Kill Wing Valve

• Application:- To permit entry of kill fluid into the completion string and also

for pressure equalisation across tree valves, e.g. during wireline operations or

prior to the removal/opening of a sub-surface safety valve.

• Operation:- Manual.

Kill fluid is a high density fluid designed to overcome and control formation pressures in

the event of an emergency or, if for any reason it is necessary to remove the Xmas tree

from the wellhead.

4.2.5 Choke Valve

• Application:- Utilised to restrict, control or regulate the flow of

hydrocarbons to the production facilities.

• Operation:- Manual or automatic.

This valve may be of the fixed or adjustable type. It is the only valve in the Xmas tree that

is used to control flow.

NOTE: All other valves used on Xmas trees are invariably the gate valve type

providing full bore access to the well i.e. the valve must be operated in the

fully open/fully closed positions.

4.2.6 Swab Valve

• Application:- This permits vertical entry to the well for well intervention

such as wireline, coiled tubing and snubbing methods.

• Operation:- Manual.

The swab valve is the uppermost valve on the Xmas Tree. In combination with a wireline

lubricator, refer to Figure 4.2, it allows the running of wireline tools, instruments, and other

equipment into the well, under pressure.

4.3 XMAS TREE CAP

• Application:- Provides the appropriate connection for the wireline lubricator.

• Installation:- Directly above the swab valve.

The Xmas tree cap normally incorporates a quick union-type connection, which should be

capable of supporting the lubricator for wireline work. The ID should permit the running of

wireline equipment compatible with the tubing size.

CAUTION: Always ensure that swab valve is closed and that pressure is fully bled off before attempting to remove the Xmas tree cap.

NOTE: The Xmas tree should have a rated working pressure greater than the

closed in tubing head pressure of a well.

All Xmas tree valves and components must, at minimum, meet API Spec. 6A -

Specifications for wellhead equipment, which specifies all essential dimensions,

pressure/temperature ratings, material properties and composition, and testing procedures.

The throughbore of a Xmas tree is specified by API and is generally 1/16 inch larger than

the tubing ID.

Figure 4.2 - Wireline Surface Equipment

5 WHAT IS WIRELINE?

5.1 INTRODUCTION

Through all stages of drilling, testing, completion and production, wireline procedures will

be used extensively for work-over, data gathering and operational requirements. Modern

wireline techniques and equipment have developed and improved enormously as the whole

oil industry itself has developed.

Originally, wireline was conceived as an early method of determining the depth of a well

accurately, by lowering a flat section, graduated steel tape into the well from a hand-

operated reel.

As depths increased, the difficulties associated with this technique grew until it was no

longer safe or practicable. The tape was replaced by a circular section of slickline or

measuring line, which allowed superior sealing properties when the survey was performed

under well pressure.

The line was marked in equal increments and calibrated measuring wheels introduced.

These ‘Veeder Root’ counters are very similar to those in use today. Larger diameter lines

were introduced as new demands on the line, such as removal of deposits, installation and

removal of flow control devices were made. The grade of solid steel line has progressed to

the modern line in use today of +25,000 ft. length and extremely high tensile strength.

Downhole equipment was now being designed with the greater wireline capability in mind.

This equipment included tubing plugs, to enable the tubing to be run and pulled under

pressure, bottom hole chokes for gas wells to prevent freezing of surface flow lines caused

by choking at the surface, running straight hole survey instruments, known as ‘sypho’ and

operation of the first regulated gas lift valve, known as the Nixon valve. The Nixon valve

was opened by upward movement of the slickline, controlled at the surface by timing

devices. As the wireline was pulled upward, tools attached to the lower end opened the

valve, allowing the gas to enter the tubing from the annulus. This early method of gas lift

operations was followed by gas lift valves which could be removed and repaired or

adjusted and reset by the use of wireline tools.

The wireline winch unit has developed from a hand-operated reel or motor, driven from the

rear axle of a car, to the modern skid-mounted, self-contained module, driven electrically,

mechanically or hydraulically and fully equipped with tools and wellhead equipment to

safely service gas or oil wells under pressure.

Wireline may be referred to by a number of names. Solid single strand line may be

described as:

• Slickline

• Wireline

Multistrand wirelines are usually described as braided line.

As well depths have increased over the years since the first measuring lines were brought

into use, accompanied by increased working loads, it has become necessary to develop

wireline having a high strength/weight ratio.

There is a need for strength to accomplish the operation without the wire breaking, and a

need to keep the diameter of the wire as small as possible for the following reasons:

• It reduces the load of its own weight

• It can be run over smaller diameter sheaves, and wound on smaller diameter

spools or reels without overstressing by bending

• It keeps the reel drum size to a minimum

• It provides a small cross-section area for operation under pressure.

The sizes of solid wireline in most common uses are: 0.108ins and 0.125ins diameter, and

are obtainable from the drawing mills in one-piece standard lengths of 18,000, 20,000,

25,000 and 30,000 ft.

The most popular material for wireline is improved plough steel (IPS), because of its high

ultimate tensile strength, good ductility, and relatively low cost. Experience indicates that

improved plough steel usually performs better than the more expensive special steel lines,

even in corrosive conditions - although then it must be used with an appropriate inhibitor

(e.g. Servo CK352 or CK356). For Sweet Wells IPS can be used with inhibitor for high

loads and long service. For Sour Wells IPS can be used with inhibitor for high loads and

short operating time.

When selecting or operating with wireline, various factors, such as the following, have

been considered:

• Physical properties

• Resistance to corrosion

• Effect of bending

• Total stress

• Care and handling.

Due to the H2S content of many wells special materials such as 0.108 ins NITRONIC-50

manufactured by Bridon Wire, or stainless steels are used. Although these are not as strong

as IPS, they have an excellent resistance to H2S corrosion.

Refer to Expro Wireline Operational Guidelines for further information.

The following table shows the relative strengths of IPS. (Improved Plough Steel) wire and

H2S resistant alloy wirelines: General Comparison of Grades.

Steel Specifications Strength Relative to

API

General Corrosion

Resistance Rating

Carbon Steel - Bright API-9A API-9A Poor

Drawn Galvanised API-9A API-9A Better

Ultra High Tensile Bridon UHT 25% Higher Poor

Stainless - 304 Type Bridon API-9A Good

316 Type Bridon 10% Lower Better than 304

Supa 60 Bridon 15/20% Lower Excellent

Supa 70 Bridon 5% Higher Excellent

Supa 75 Bridon Similar Better than Supa 70

Table 5.1

Carbon Steel Wires to API-9A

The wire is supplied on steel reels in continuous lengths. Diameter tolerance + 0.001 inch.

Torsion in all cases in accordance with API-9A.

Nominal

Diameter

Nominal Weight

per 1000 ft

Recommended

Minimum Pulley

Minimum Breaking Load

Dia Bright UHT Bright

ins lbs ins lbs lbf

0.092 22.69 11.25 1547 1980

0.108 31.11 13.00 2120 2720

0.125 41.80 15.00 2840 3640

Table 5.2

Stainless Steel and Special Alloys

All stainless steel and Special Alloy wires are supplied on nylon coated steel reels in

continuous lengths, to the following Bridon specifications.

• Diameter tolerance + 0.001 ins

• Ductility wraps on own diameter - 8 minimum.

Nominal Rec’d Minimum Breaking

Load

Diameter Nett

Weight

Pulley 304 316 Supa 60 Supa 70 Supa 75

per 1000

ft

Diameter

ins lbs ins lbf lbf lbf lbf lbf

0.092 22.90 11.25 1550 1400 1260 1600 1470

0.108 31.55 13.00 2100 1850 1720 2100 2030

0.125 42.26 15.00 2700 2500 2220 2600 2526

Table 5.3

5.2 BENDING STRESSES

The bending stresses that the line is subjected to are the most common cause of breaking

but are generally the least considered. Bending occurs whenever a line deviates from a

straight line condition, such as when it passes over pulleys or reel drum, or when it is

flexed by hand.

It is necessary to employ specific mechanical equipment, such as the reel drum, hay pulley,

stuffing box pulley and measuring wheel, when carrying out wireline operations. Each time

the line passes over a pulley it is subjected to two bending stresses - when it changes from a

straight to a curved path and again when it reverts to a straight path. It is subject to only

one when it leaves the reel drum. So, for each trip in and out of the well, the line probably

suffers a minimum of fourteen bending cycles.

Note: To minimise the effect of bending stresses on the wireline, 50-100 ft. is

normally cut and discarded every time a new rope-socket is tied. This

action will subject a different part of the wireline to bending stresses.

5.3 RE-SPOOLING

The life span of any wireline can be extended by using correct spooling procedures. The

new wire should be spooled on to the unit drum with 250-400 lbs strain on it. Five to seven

bedding wraps of carefully aligned wire are recommended to provide a firm base. This also

indicates during subsequent wireline operations that only a small amount of wire remains

on the drum.

Correct procedures for spooling new wire on a reel are shown overleaf to minimise stress

in the line.

Figure 5.1 - Re-Spooling

5.4 HANDLING AND STORAGE

Although steel wireline has a high strength-to-weight ratio, it still requires proper handling

and storage. IPS should be stored with a lubricant covering over the surface of the wire

(i.e. grease, grease paper).

If not crated, wireline spools should be lifted with a nylon sling to avoid damage to the

wire.

When a wireline job is completed, the wire should be lubricated and covered to protect

against corrosion.

Alloy wire spools should also be kept covered as they are not totally immune to

corrosive/erosive atmospheres.

Spool

Spool

Spool

Spool

Reel

Reel

Reel

Reel

Correct Method

Incorrect Method

5.5 GENERAL SAFETY PRECAUTIONS

1) There is a certain amount of tension in a coil of wire, so when it is unfastened, care

should be taken to make sure that the leading end does not lash out. Ensure that the

free end is always under control.

2) Ensure that hard hats, safety boots/shoes, coveralls, safety glasses, gloves are worn.

3) Never carry out flame cutting or welding operations near reels of wireline. Heat or

metal spray coming in contact with the wire could change the condition of the steel

significantly and lead to early failure in use.

4) Throughout all wireline operations the immediate area around the path of the wire

must be cordoned off.

Damage and abuse may not always be obvious, or the significance be appreciated, and

effects are cumulative. There are three main categories:

• Mechanical damage

• Corrosion

• Wire winding practice.

These are summarised in the following table under fault, cause, result and correction.

Fault and Causes Results Correction

Damage to reels: Bending of flanges, distortion of barrel. Caused by dropping.

Wire snapping during unwinding.

Use sling when handling reels or use ramps. Do not drop.

Corrosion in store: Carbon steel wire is oiled but, if stored uncovered, corrosion will develop at varying rates depending on climate. Alloy steels are for use under corrosive conditions but they are not completely immune and, where there are wind blown salts, slight damage may occur.

Under worst conditions there will be pitting of the surface and local reduction in strength. Slight damage at this stage, which may be scarcely visible, could increase the risk of alloy wire corrosion in service.

All types of wire: store reels upright (on edge) on a level, solid base in dry, covered conditions. If a permanent store is not available, support reels off the ground under waterproof cover. The latter should be kept out of contact with the wire and fastened down just clear of the ground to allow air to circulate and minimise condensation.

Corrosion in service: There are inevitable hazards of well conditions and environment.

There may be development of surface pitting. At worst there may be stress corrosion or hydrogen embrittlement causing brittle failure.

When rewinding wire, wipe off well contamination. If carbon steel wire reels are to be put back into store, re-oil the wire during rewind. Do not leave any wireline downhole unless it is necessary.

Wire winding practice: Wire damage may be caused at various stages in winding onto the service reel from the supply reel or in rewind during use. To ensure good spooling, it is recommended that an intermediate capstan is used between the supply reel and the wireline unit drum to develop a high line tension without risk of cutting down. Practices are followed in the running of wirelines that have to strike a balance between operational convenience and wireline life. To the user , some of the possibilities listed here may seem unlikely to happen but they are given so that, if any should occur, their significance will not be ignored.

1. Uneven winds: Variable tension and/or poor control or wire traversing the barrel.

Wire pullsdown between adjacent turns preventing free running, causing snags and possibly wire breaks.

Maintain a regular traverse of the wire across the full width of the barrel to give uniform build up of layers. Course pitch and tension during winding onto the reel will minimise the risk of the wire pulling down.

2. Loops and bends: Insufficient braking on the supply reel.

Overrunning with the risk of snarls forming in looped wire. Even if the snarl is straightened out by hand, there can be a significant reduction in strength. Overrun wire may be pulled over a reel flange and be sharply bent.

Whatever the method used to keep the wire under tension during winding, a brake on the supply reel is desirable so that too much slack wire does not appear between the two reels.

Fault and Cause Result Correction 3. Wire abrasion: Rubbing on the ground caused by slack wire. Rubbing on reel side caused by incorrect traversing.

Reduction in wire strength as a result of loss of cross-sectional area of steel. Reduction in cross-sectional area.

Keep tension and always wind from ‘top’ to ‘top’ of reels. In service, rewind on top of the reel. Angle of the wire during traverse and total traverse must be controlled.

4. ‘Wild’ wire: Cause by slack winding or by reversing the natural curvature of the wire.

Wire may be difficult to control and lead to tangles and snarling.

Always wind the wire in the direction of its natural curvature. Never wind from the top of one reel to the underside of the other.

5. Wire indentation: Caused by ‘cross-cutting’ between layers of wire.

Reduction in strength. Avoid excessive tension in winding and excessive ‘jarring’ when operating downhole tools.

6. Friction on pulleys: Possible during ‘jarring’.

Embrittlement of wire surface. Shock loads can produce high surges out of all proportion to the assumed loads on the wire and may cause failure.

Avoid excessive ‘jarring’. Cutting the wire between uses minimises the chance of cumulative damage.

7. Fatigue cracks: Caused by repeated bending under high stress.

Wire failure, particularly if other factors noted above are contributing.

Ratio of pulley and wire diameter should preferably be 120:1 to reduce the significance of bending.

Table 5.4

5.6 WIRELINE TORSION TESTER

The portable torsion tester is designed to be able to test wirelines in the field in compliance

with API 9A and the Health and Safety at Work Act 1974.

5.6.1 Objective

To measure the number of twists an 8 ins long sample piece of wireline can withstand

before breakage occurs. Recording these results in a log allows a performance curve to be

drawn showing the lifespan of a wireline in relationship to it's usage. This highlights the

current em-brittlement in a line prior to carrying out further wireline operations.

5.6.2 Procedure

1) Pull approximately 50 ft of wire from the drum, cut a small length and prepare a

specimen (see specimen configuration). See Figure 5.3.

2) Place the specimen through the jaws of the tester. Set the jaws at the appropriate

marks which provide the wire gauge length of 8 ins. between the jaws.

3) Tighten down the Allen holding screws sufficiently to hold the wire in place during

the test. See Figure 5.4.

4) Close the tester lid and secure the latch. See Figure 5.2.

5) Rotate the handle at a constant rate of approximately 60 turns per minute (60 rpm)

until the wire parts. Count and record the number of turns taken to part the wire and

if the total of rotations is not a whole number, round up if the part rotation is equal to

or greater than a half turn.

6) Unlatch and open lid, (caution – wire will be hot), remove the wire ends from the

jaws and inspect for a lean shear (see fracture analysis). Record the number of turns

or rotations into the log book and any relevant information from the analysis.

7) The torsion test should be carried out at the start of any wireline operations and

thereafter every time a new rope socket connection is made. If the number of

rotations is less than operators or manufacturers guidelines, refer to wireline test

analysis.

8) The torsion test recordings should be entered into the log book along with the other

wireline history.

Ductility Tester

TORSION REQUIREMENTS OF THE API-9A SPECIFICATION

Nominal Wire Diameter 0.092 0.108 0.125

Minimum Number of Twists in 8” 23 19 17

Table 5.5

WARNING: ALWAYS WEAR EYE PROTECTION WHEN USING WIRE TESTER.

Date Wire Spooled Total Length 20,000 ft Date Type of Job No. of

Runs Footage

Run No of Turns

Type of Break

Wire Cut Off

(ft)

Balance Remaining

13-11-94 Ball/ v Change 8 2,400 23 Good 50 19,950 18-11-94 Gauge Rings +

Tag Fill 4 14,000 21 Good 50 19,900

20-11-94 Set Plug TBG Test

5 8,500 21 OK 50 19,850

9-12-94 Bailing 16 11,250 17 OK 500 19,350 12-12-94 Fishing 14 12,100 15 Good 300 19,050 25-12-94 Plugs For

Completion 8 10,800 13 OK 500 18,550

Recommended Wire Change

Table 5.6

The above chart is only for comparison purpose. In real life conditions wire would

probably last much longer.

5.6.3 Slickline Operation And Maintenance

To ensure the wireline performs effectively throughout its working life it is imperative it is

kept in optimum condition. For this purpose a log book shall be kept showing up-to-date

details of the following:

• Date wire spooled onto reel.

• Amount of wireline spooled on.

• Amount of bedding wraps.

• Length of exposure to well fluids.

• Type of well fluids.

• Depth of wireline operation.

• Maximum strain exerted on the wireline during the operation.

• Amount of wireline cut off after the operation.

• Amount of wireline remaining on the reel.

• Torsion test result at the cut off point, if applicable

Operation

i) Ascertain whether the wireline on the drum is suitable for the working

environment expected. If H2S or CO2 is encountered with plough steel wireline, a

chemical inhibitor shall be used.

j) Ascertain from the log book whether there is sufficient wireline on the drum to

perform the deepest operation.

k) Torsion test the wireline prior to rigging up and after re-tying the wireline rope

socket.

l) Ensure the path of the wireline is unrestricted during all operations.

m) Minimise the amount of hay pulleys in the rig up to reduce bending stresses

through out the operation.

n) Use the recommended hay pulley diameters for the size and type of wireline in

service to reduce the bending and fibre stresses in the wireline.

o) The extent of jarring up operations should be restricted to 50% of the breaking

strain of the wireline when new.

p) A line wiper shall be used to remove all well fluids from the wireline while pulling

out of the hole.

q) Apply a light coat of oil to the wireline while pulling out of the hole.

r) Ensure the wireline is protected with a film of grease or denso-tape during periods

between wireline operations.

Figure 5.2 - Linetech Torsion Tester

5.6.4 Torsion Test Specimen Configuration

Unlike conventional torsion testers, this machine has been designed to test prepared

wireline samples of a specific length and configuration:

Figure 5.3 - Test Specimen Configuration

The reasons for selecting a wire sample of this configuration is that, in conjunction with the

fixed machine dimensions, a constant test gauge length of 8 ins. is always achieved

between the jaws of the machine when the wire sample is clamped in position which

ensures accurate testing and compliance with Section 3.10 of the API 9A specification.

The purpose of the right angled bends, formed on each end of the wire test piece, are to

prevent slippage of the wire in the jaws during rotational twisting. This technique permits

the use of flat-faced jaws, which minimise the likelihood of invalid tests due to sample

damage and jaw failures.

Figure 5.4 - Wire in Flat Faced Jaw

5.7 WIRELINE TEST ANALYSIS

5.7.1 Acceptance

5/8"

10 1/4"

8"

5/8"

10 1/4"

If the number of turns is satisfactory, the test piece is deemed to have passed the test,

irrespective of the position of the failure. If the number of turns does not satisfy the

requirements of the specification and if failure is within 1/8 ins of the grips, the test shall be

considered as invalid and shall be repeated.

If, when making any individual test, the first specimen fails then two additional specimens

shall be tested. The average from any two will then be taken as the value to represent the

wire. If these also fail, 500 ft of wire will be pulled from the drum and the test repeated. On

further failure of the tests, a maximum of two more 500 ft lengths shall be removed and

tests conducted. If after this the wireline still fails the tests, the Wireline Supervisor should

be informed in order to make a decision on the disposition of the line.

5.7.2 Torsion Fracture Analysis

Few people appreciate the significance of the torsion test as a definitive wire quality arbiter

for carbon steel wirelines. It is not just the number of twists to failure that is important, but

more specifically, whether the material exhibits a "ductile" or a "brittle" primary fracture.

In general, three types of primary wire fracture may be encountered at the conclusion of a

torsion test, these are categorised as follows.

5.7.3 Fracture Classification

Grade 1 Fracture without Secondary

Breaks.

After testing, the sample should contain

a single fracture which is square ended

(sometimes called a "Ball and Socket"

break). Figure 5.5 There should be no

evidence of spiral splitting on the sample

and no secondary fractures.

This type of fracture is characteristic in

wire a suitable condition for continued

use. It is usually associated with a high

number of turns before failure.

Figure 5.5 - Single-Square Ended Primary Fracture

Grade 1 Fracture with Secondary Breaks

Sometimes a grade 1 fracture may be

accompanied by a secondary helical-

shaped fracture. See Figure 5.6. This

secondary fracture is a result of the

instantaneous release of stored energy

when the primary fracture occurs. It is

termed a "recoil" fracture.

Although a recoil fracture indicates a

slight reduction in torsional strength and

ductility, it can be discounted. The main

concern is the primary fracture and this is

a true reflection of the wire condition.

Figure 5.6- Single-Square Ended Primary

Fracture with Secondary Breaks

Grade 2 Fractures

Although containing a square-ended

break, a grade 2 sample primary fracture

may be slightly stepped. Figure 5.7.

Secondary helical fractures may be

present and slight spiral splitting may also

be in evidence.

This type of primary fracture is usually

associated with a lower number of turns

before failure.

Figure 5.7- Slightly Stepped Primary

Fracture

Grade 3 Fractures

The primary fracture will show a severely

stepped or helical type break, usually

associated with secondary fractures.

Figure 5.8 Spiral splitting will almost

certainly be present along with localised

twisting.

A secondary break is not usually present

as the primary break is associated with a

low number of turns to failure.

This sample would be unacceptable for

further use. Re-testing would be required

after spooling off approximately 500 ft of

wire.

Figure 5.8- Single -Helical Spear Type

Fracture

5.7.4 General Guidance Notes

It should be noted that any torsion test performed relates only to the test piece and does not

guarantee the quality of the remaining length of wireline.

In the event of obtaining Grade 2 or Grade 3 type fracture characteristics two repeat tests

shall be performed. If the quality of a wireline is variable, it is permissible to cut off a

length (say 200 ft) and re-test. Two re-tests should both give Grade 1 type fractures. This

procedure may, if necessary, be repeated since it is well known that the ductility of a

wireline deteriorates more rapidly at bottom hole temperatures.

6 QUICK UNIONS

6.1 INTRODUCTION

The connections used to assemble the lubricator and related equipment are referred to as

Quick Unions. They are designed to be quickly and easily connected by hand.

The box end receives the pin end, which carries an O-ring seal. The collar has an internal

ACME thread to match the external thread on the box end. This thread makes up quickly

by hand and must be kept clean. The O-ring forms the seal to contain the pressure and

must be thoroughly inspected for damage and replaced if necessary. A light film of oil or

grease on the pin and O-ring helps in the make up of the union and helps to prevent cutting

of the O-ring. A coating of light oil may be used on the threads (not grease). Pipe

wrenches, chain tongs or hammers must never be used to loosen the collar of the

union. If it cannot be turned by hand, all precautions must be taken to make sure that the

well pressure has been completely released.

Figure 6.1 – ‘O’ Ring Seals

NOTE: In general, unions that cannot be loosened easily by hand may indicate

that pressure may be trapped inside. Ensure that all pressure is released

“before” unscrewing the union.

NOTE: Before making up quick unions the ‘O’ ring and threads should be

checked.

The collar of the union will make up by hand with the pin end, when the O-ring has been

shouldered against the box end. When the collar bottoms out, it should be backed off

approximately one quarter turn to eliminate any possibility of it sticking due to friction

when the time comes to disconnect it.

Rocking the lubricator to ensure it is perfectly straight will assist in loosening the quick

union. Make sure that tugger lines and hoists are properly placed to lift the lubricator

assembly directly in line over the wellhead.

Otis and Bowen manufacture the two most common types of quick union. See Figure 6.2.

Figure 6.2 - Otis and Bowen Quick Unions

6.1.1 Differences between Otis and Bowen Quick Unions.

External Difference

Bowen has external holes in the collar.

Internal Difference

Otis has internal angles in the box, Bowen has a straight shoulder.

Quick Union

Thread (ins)

Threads Per

Inch

Max. Working

Pressure (psi)

H2S

Service

Inside Dia.

(ins)

Seal Dia.

(ins)

Collar Dia.

(ins)

5.000 4 5,000 Yes 2.500 3.500 5.77

5.750 4 10,000 Yes 3.000 4.000 7.02

6.000 4 5,000 Yes 4.000 4.875 6.75

6.500 4 5,000 Yes 4.000 4.750 7.52

6.500 4 10,000 Yes 3.000 5.138 7.52

8.250 4 5,000 Yes 5.500 6.188 9.52

8.375 4 10,000 Yes 4.000 5.250 9.55

8.375 4 5,000 Yes 6.375 7.500 9.77

9.000 4 10,000 Yes 5.000 6.750 10.52

9.500 4 5,000 Yes 6.375 8.000 10.52

11.500 4 10,000 Yes 6.375 8.250 13.02

Table 6.1 - Standard Otis Quick Union

Quick Union

Thread (ins)

Threads Per

Inch

Max. Working

Pressure (psi)

H2S

Service

Inside Dia.

(ins)

Seal Dia.

(ins)

Collar Dia.

(ins)

4.750 4 5,000 Yes 2.500 3.750 6.02

5.500 4 x 2 st 5,000 Yes 3.000 4.375 6.34

6.312 4 10,000 Yes 3.000 4.375 7.52

6.000 4 x 2 st 5,000 Yes 3.000 4.875 6.77

8.250 4 x 2 st 10,000 Yes 4.000 6.000 9.46

7.000 5 5,000 Yes 4.000 5.250 7.77

8.250 4 x 2 st 5,000 Yes 5.000 6.750 9.52

8.875 4 x 2 st 10,000 Yes 5.000 6.500 10.40

9.875 4 x 2 st 5,000 Yes 6.375 8.000 10.90

Table 6.2 - Standard Bowen Quick Unions

6.1.2 Wellhead Adapter (Tree Adapter)

All Wellhead Adapters are crossovers from Xmas tree to the bottom connection of the

Wireline Valve or Riser. It is important to check that the correct type of threads with

appropriate pressure ratings are used on the top and bottom of the adapter.

Three types of Wellhead Adapter; See Figure 6.3, are in common use:

• Quick Union to Quick Union.

• API Flange to Quick Union.

• Acme Thread to Quick Union.

Figure 6.3 - Wellhead Adapters

6.1.3 Pump-In Tee

A Pump-in Tee; see Figure 6.4, consists of three main parts:

• A Quick Union box end.

• A Quick Union pin end.

• A Chiksan/Weco type connection.

The Pump-in Tee, can be placed between the Wellhead adapter and the wireline BOP.

Therefore, Quick Union sizes and pressure ratings must be compatible with all surface

equipment.

Pump-in Tees may be required as part of a wireline rig-up. By connecting a kill-line to the

Chicksan/Weco connection, the well can be killed in an emergency situation. The line can

also be used to pressure test or release pressure from the surface equipment.

NOTE: On some locations, the pump-in tee will be part of the wellhead adapter.

Figure 6.4 - Pump-in Tee

6.1.4 Wireline Blow Out Preventer (BOP)

s) Description

A blowout preventer (BOP) or wireline valve must always be installed between the

wellhead/Xmas tree and wireline lubricator. The BOP is a piece of safety equipment that

can close around the wireline and seal off the well below it. This enables the pressure to be

bled off above it, allowing work or repairs to be carried out on equipment above the BOP

without pulling the wireline tools to surface. A positive seal is accomplished by means of

rams which are manually or hydraulically closed without causing damage to the wire.

Hydraulically actuated BOPs are more commonly used because of the speed of closing

action and ease of operation. Often during an emergency, the BOP is not easily accessible

to allow fast manual operation and therefore remote actuation is preferred.

Single or dual ram BOPs are available in various sizes and in a full range of working

pressure ratings. Dual rams offer increased safety during slick line work and allow the

injection of grease to secure a seal on braided wireline. They are used particularly in gas

wells, or wells with a gas cap at surface.

BOPs are fitted with equalising valves that allow lubricator and well pressure to equalise

prior to opening the rams when wireline operations are to be resumed. Without this, if the

BOP rams were to be opened without first equalising, the pressure surge can blow the tool

or wire into the top of the lubricator, causing damage or breakage.

Care must be taken with hydraulic BOPs to ensure that hydraulic pressure is kept to a

minimum when closing Rams.

Example: 7” BOP with 7” pistons closed with 1000 psi per piston.

Force = Pressure x Area

Area = π D2

4

= 3.142 x 72

4

= 38.48 in2

F = P x A

= 1000 (Piston Pump Pressure) x 38.48 (Piston Area)

= 38,480 lbs per Ram/Piston

= 38.480

2240 = 17.17 Tons Per Piston

At this pressure, damage can occur to the stem, keyways and possibly guide inserts.

NOTE: Keep the Piston Pressure to a minimum. (Do not exceed operating

pressure)

WARNING: Since they are such a vital component controlling the safety of the well, it is important that bop's are regularly pressure and function tested. tests must be carried out prior to transport offshore, before each new wireline operation, and after any redress or repair of the bop.

t) Use of BOPs

• To enable well pressure to be isolated from the lubricator when leaks develop

etc. without cutting wire by closing the master valve.

• To permit assembly of a wireline cutter above the rams.

• To permit dropping of wireline cutter or cutter bar.

• To permit "stripping" of wire through closed rams though only when absolutely

necessary.

u) Description of Operation

A mechanical or hydraulic force is applied to close the rams to seal against well pressure.

The sealing elements are arranged so that the differential pressure across them forces them

closed and upwards, assisting in the sealing action.

CAUTION: Wireline BOP's will hold pressure from below only.

v) Equalising Valve

Permits equalisation of pressure from below the closed rams, after bleed off of the

lubricator. The equalising valve must be opened and closed prior to use.

Check that the equalising assembly is not inverted and that the Allen screw is towards the

bottom of the BOP.

Figure 6.5 - Wireline BOP

6.2 WIRELINE BOP

6.2.1 Pressure Testing Of Wireline BOP

Prior to BOP being used in operations they must first be fully function tested and pressure

tested.

Function testing

1) Ensure BOP rams are in the fully open position

2) Drift BOP with the appropriate size drift

3) Close BOPs, visually confirm BOP s are closed

4) Re-open BOPs

Pressure testing

1) With the BOPs installed (on test stump or rig-up)

2) Close BOP rams

3) Open the equalising valve on the BOP and fill with test fluid to purge the air from the

system then close the equalising valve

4) Low pressure test from below to required test pressure and hold for 3 minutes

5) High pressure test and hold for 15 minutes

6) Bleed pressure to zero

7) Open equalising valve prior to hydraulically opening the rams

NOTE:- Refer to Expro Operational Guidelines

Maintenance

Maintenance must be carried out on a regular basis, or after every time a BOP has been

operated against wire.

BOPs must be fully stripped down and all seals and sealing faces inspected for damage.

Any damaged seals must be replaced, on completion of maintenance BOP must be function

tested and pressure tested.

Relationship between test pressure and working pressure

All surface equipment should be manufactured and fabricated in accordance with

applicable provisions of the code of pressure piping, ANSI BSI series. ASTM. AISI or

API specification materials, other than those acceptable under ANSI BSI series piping

codes, may be used provided that they are satisfactory for the intended service and welding

procedures and welders are qualified for the material used.

A drift, visual and pressure test check of all sections of the lubricator should be made at

intervals not to exceed 6 months. The pressure test, using cold water, should be made at

least one and one and a half times the lubricator working pressure should not exceed its

rated test pressure. The wireline BOP should be tested in both the open and closed

positions.

6.3 LUBRICATORS

The lubricator is in effect a pressure vessel situated above the Xmas tree, subject to the

wellhead shut-in pressure and also test pressures. For this reason it must be regularly

inspected and tested in accordance with statutory regulations.

All lubricator sections and accessories subject to pressure are to be banded with stainless

steel, with maximum working pressure, test pressure, and date and rating of last hydrostatic

test.

w) Description

A lubricator allows wireline tools to enter or be removed from the well under pressure.

The lubricator is a tube of selected ID and can be connected with other sections to the

desired length by means of "quick unions".

The following factors govern the selection of lubricators:

• Shut-in wellhead pressure and well fluid

• Wireline tool diameter

• Length of wireline tools.

The bottom lubricator section normally has one or more bleed off valves installed; a

pressure gauge can be connected to one of the valves to monitor pressure in the lubricator.

If the lubricator has no facility to install valves then a "bleed off sub", a short lubricator

section with two valves fitted should be connected between the BOP and lubricator.

NOTE: The minimum length of the lubricator must be longer than the maximum

length of the toolstring to be run/pulled.

x) Construction

Quick unions are used to connect the lubricator sections together and to secure them to the

BOP. In general Carbon or Manganese Steels are used to manufacture components for

pressure ratings up to 15,000 psi. For sour service (H2S), the steel is manufactured to a

controlled hardness per NACE (National Association of Corrosive Engineers)

specifications. The materials are heat treated so that they are safer since H2S embrittles

metal and causes stress cracking.

All lubricators must have full certification from the manufacturer or test house.

A standard colour code identifies different pressure ratings of lubricator. This code is only

standard for each company and is not an industry standard. (Colours may vary from

company to company).

Figure 6.6 – Lubricators

e.g. Basic colour of surface equipment Blue, with a band of following colour:

Pressure Rating Band Colour

1000 psi Silver

1440 psi Yellow

5000 psi Red

7500 psi Brown

10,000 psi Black

15,000 psi Purple

Sour Service Green

Table 6.3 – Standard Colour Codes

6.3.1 Injection Sub

An injection sub; see Figure 6.7, resembles a short lubricator section with quick union

connections at either end.

The injection sub should be installed immediately below the stuffing box in the surface rig-

up. A check valve is installed in the body of the injection sub as part of the injection line.

The purpose of the check valve is to contain well pressure in the event of hose failure and

must be in working order.

The injection sub is used to introduce fluids into the lubricator during wireline operations

to counteract one or more of the following :

• Corrosive environments (e.g. H2S).

• Hydrate formation (glycol injection/methanol injection).

• Dry gas conditions.

Figure 6.7 - Injection Sub

6.4 CUTTER VALVE

Description

The cutter valve is a surface mounted valve permitting pressure tight closure of the well

during thru-tubing wireline, electric line or coiled tubing operations. The valve will

simultaneously cut wire and coiled tubing, closing in the well, without the need to

manipulate the Xmas tree master valve. Opening and closing of the valve is achieved by

applying pump pressure, it is not a failsafe device. The ball and seat are fitted with

replaceable cutting inserts, minimising the risk of damage to the ball and seat assemblies

during cutting operations.

Application

The valve is installed on the wellhead prior to performing wireline or coiled tubing

operations, and in an emergency, is closed instead of the master valve.

The valve is normally used as a self-contained unit, with a dedicated accumulator, but may

also be incorporated as part of a well service control system. (Well control – See section

10).

FEATURES BENEFITS

Compact Design Allows safe installation when wellhead access

is restricted.

Cut and seal capability Automatic containment of well pressure, once

the cut is made and the valve is closed.

Replaceable cutter inserts Reduced maintenance costs with quicker

turnaround time during redress.

T-Seal Technology Improved seal life with lower frictional losses.

4140 H2S Service Ball H2S Service as per NACE.

Table 6.4 – Cutter Valve Features

6.5 WORKOVER VALVE

Description

The workover valve is a surface mounted valve, permitting pressure tight closure of the

well during through-tubing work. (Slickline, electric line etc.) the valve can be made to

have wire cutting capability, this would allow the valve to cut through lines up to 7/32” in

size. However this should only be used in an emergency. e.g. an abandon platform alarm.

Application

The valve is placed onto a quick union connection, usually during a work over or fishing

operations and can be closed in an emergency i.e. the well fluids coming back on line

during a work over.

6.6 STUFFING BOX

The stuffing box is a sealing device connected to the top of the lubricator sections. It allows

the wireline to enter the well under pressure and also provides a seal should the wireline

break and be blown out of the packing. The stuffing box will cater for all sizes of slickline

but the size of the wire must be specified to ensure the correct packing rubbers, upper +

lower gland, and BOP are installed.

If the wireline breaks in the well, the loss of weight on the wire at surface allows well

pressure to eject the wire from the well. To prevent well fluids leaking out the hole left by

the wire, an internal blow out preventer plunger is forced up into the stuffing box by well

pressure and seals against the lower gland.

A packing nut and gland located at the top of the stuffing box can be adjusted to tighten the

packing and lubricate the wireline. Hydraulic controlled packing nuts are available to ease

operation should the packing require to be tightened during wireline operations.

There are a variety of stuffing box packing materials available to suit well conditons and

need to be selected accordingly.

For slickline operations the top sheave is normally an integral part of the stuffing box, this

reduces the rig up equipment required and the large 10 or 16 inch sheaves can handle the

larger OD wire with less fatigue and breakdown.

Wireline sealing devices fulfil one of two functions:

• Pressure containment (sealing)

• High pressure containment on braided line.

For solid wirelines, only pressure-containing stuffing boxes are utilised. The standard

stuffing box is available in 5000 psi and 10,000 psi pressure ratings. Higher pressure

ratings are now also available.

The essential function of the wireline stuffing box is to ensure containment or sealing off

around solid wirelines, whether stationary or in motion, at the upper end of the lubricator

during wireline operations. In addition, most stuffing boxes contain a BOP plunger which

seals off flow in the event that the wireline breaks and is forced out of the packing section.

A swivel-mounted (360 free movement) sheave wheel and guard are fitted to the top half of

the stuffing box. The wheel is positioned so as to maintain the passage of the wire through

the centre of the packing rubbers.

The sheave guard on the stuffing box is designed to stop wire jumping out of the groove in

sheave when jarring.

6.6.1 Stuffing Box Re-Packing Procedure

1) Place stuffing box in a Baker vice and secure on main body.

2) Remove hydraulic/manual packing nut.

3) Use correct packing pulling tool to remove all of the packings from the packing

gland. All of the packings should be counted and replaced.

4) The plunger stop, plunger and lower gland should be removed and checked for wear

and replaced if worn.

5) The same number of packings should be selected; the type of packing will be decided

by well conditions.

6) A length of the wire should be taken (3 to 4 foot) and indents made by the wire

cutters should be made approx ¼” apart. These marks are for ‘reaming’ the packing

before it’s placed inside the packing bore.

7) Carefully place the selected packings on to the wire, one at a time. Note:- the end of

the wire can be filed in to a point to assist the packings on to the wire. Gloves and

glasses should be worn at all times and care taken with the wire.

8) Once all the packings are on the wire, one packing at a time should be rubbed or

reamed over the indents to size the packings to the correct size. Packings should

move easily on the wire once it has cooled. Note:- the wire and packings can cause

burns to the hands when reaming is taking place.

9) The lower gland should be replaced before starting to repack the packing gland.

10) Once all the packings are reamed they should be removed from the wire and placed

into the packing gland of the stuffing box. The assistance of brass shear stock can be

used to help loading of the packings. Care should be taken not to damage any of the

packings.

11) The hydraulic/manual packing nut should have been checked and any worn parts

replaced.

Figure 6.8 - Stuffing Box

6.7 HYDRAULIC PACKING NUT

The hydraulic packing nut assembly is designed for a standard wireline stuffing box to

allow remote adjustment of the packing nut. This method is a safe and convenient way of

regulating the packing nut, and is made by means of a hydraulic hand pump and hose

assembly from a ground position.

y) Benefits

• The need for a man to climb a lubricator is eliminated.

• The hand pump is positioned away from the nut itself, and possible escaping

well fluid.

z) Operation

The hydraulic packing nut assembly includes a piston which has a permissible travel of 0.4

ins enclosed in a housing. The housing has a NPT connection for a hydraulic hose.

The area above the piston is arranged so that when hydraulic pressure is applied to this

area, the piston is forced downward against the force of the spring. The downward action

of the piston is transmitted to the upper packing gland causing the stuffing box packing to

be squeezed around the wireline, sealing off well fluids within the stuffing box. Care must

be taken that the minimum hydraulic pressure is used to seal the wire. (Overpressuring will

cause premature wear on the stuffing box packing.)

Figure 6.9 - Hydraulic Stuffing Box

7 WIRELINE UNIT

The wireline winch has progressed from a hand-operated reel, driven by a belt and

propelled by a pulley attached to the rear axle of a car or pick-up to the present day

truck/skid mounted units. Today's wireline operations are often complex and demanding

with wireline work being carried out at ever increasing depths. To meet these demands, the

modern wireline unit has been developed to provide increased power and transportability

while meeting strict safety requirements.

A wireline winch is used as the means of lowering and raising toolstrings in wells that

require wireline servicing.

A winch will consist of these major assemblies:

• Wireline Drum

• Controls

• Combined Winches / Power Pack

The drum assembly can be single or double, the double drum offering the facility of

running two sizes of wireline from one winch e.g. 0.108 slickline and 3/16 ins braided line

or 0.108 ins slickline and 7/32 monoconductor, for electric line operations etc. A wireline

measuring head is installed as part of the unit assembly; head design will be dependent on

wire diameter and type.

The most common found power units to drive wireline winches are diesel powered

hydraulic systems. Electrically powered winches are also used in some areas. (Both of

these power packs are discussed later in this Section). Available hydraulic power must be

sufficient to support lengthy jarring operations; the unit has to be compact for offshore

locations and satisfy zoning regulations for hazardous area use. The power pack and winch

may be combined into one unit, or separate components may be utilised which require the

connection of hoses to complete the hydraulic circuit.

Regardless of winch design, certain basic controls are common to all types of unit.

Additional controls and instrumentation are installed to ease winch operation and will be

dependent again, on the type of unit used.

Basic controls/instruments are:

• Drum brake - to keep drum stationary or used when jarring.

• Direction lever - to select rotation direction of drum.

• Gear Box - to select speed of drum rotation. (usually 4 gears)

• Hydraulic control valve (double A valve) - to control speed of drum rotation.

• Weight indicator - to measure strain on wireline.

• Counter/Odometer - to indicate wireline depth.

Many wireline winches are equipped with a spool-off and cat-head assembly. Hydraulically

operated, this provides a facility to spool wire off or onto the wireline drum.

Figure 7.1 - Modern Self-Contained Wireline Unit

Figure 7.2 - Wireline Unit Controls

7.1 HAY PULLEY AND WEIGHT INDICATOR

7.2 HAY PULLEY

aa) Description

There is normally only one hay pulley used, its purpose being to change the direction and

level of the wire from vertical at the top of the lubricator to horizontal at the level of the

wireline unit.

The hay pulley is positioned generally at the wellhead using a pad eye and a certified sling

on offshore locations to guide the wireline from the stuffing box to the wireline unit.

The hay pulley should be so positioned that the wireline goes through an angle of 90° at the

wellhead or lubricator/riser as this is necessary to ensure accurate weight indicator readings

when the hay pulley is attached to the wellhead via a weight indicator. In addition the

location of the hay pulley must be such that wireline handling when jarring up by hand,

hand feeling of the wireline toolstring into the lubricator or when pulling out of the well,

etc. can be readily accomplished. It is also important to secure the hay pulley as close as

possible to the wellhead or riser in order to avoid lateral loading of the lubricator during

heavy jarring operations. Securing of the hay pulley to the wellhead must be accomplished

by means of a wire sling, never a rope. The hay pulley should be installed with the lock pin

facing upwards to ensure that it cannot fall out during wireline operations. Sheaves are

manufactured to suit the wireline size.

The sheave diameters for well measuring lines should be as large as the design of the

equipment will permit but not less than 120 times the diameter of the wire, otherwise cold

working of wireline material will occur, resulting in premature failure.

The hay pulley generally has a hole for the attachment of a line wiper which is used to

remove corrosive liquids and dirt from the line as it is spooled onto the drum.

bb) Maintenance

Always check the shackle connection and the swivel for wear and tear and replace any

worn parts as the connection is subject to high shock loading and the pulley can cause

severe injuries if it breaks loose.

7.3 WEIGHT INDICATOR

7.3.1 Introduction

cc) Description

Weight indicators are instruments which measure the tension placed on the wireline at the

surface. There are various types but all are either hydraulic or electronically operated. The

weight indicators commonly used are :

• The Martin Decker with the tree mounted load cell

• The unit-mounted electronic type as used in the K winch.

dd) Martin-Decker Load Cell

The most often-used weight indicator is the Martin Decker which is completely hydraulic.

The sensing load cell is attached to the Xmas tree by a sling and a heavy duty hose carries

the pressure to the fluid filled gauge.

The load cell is provided with a connection at the top to attach to the hay pulley and at the

bottom to attach to the Xmas tree forming a pull at 90°. The system is calibrated to this

angle of pull and accuracy will be marginally affected if this angle is not true but the

sensitivity of the system is always maintained. The load gap is maintained by hydraulic

fluid, so if the fluid should leak out and the gap closes, the gauge readings will be incorrect.

The gauge is a 6 ins diameter fluid filled instrument which can be fastened onto the winch.

A damper is provided on the gauge to set the pointer motion to the required sensitivity. The

fluid filled case eliminates severe vibrations, lubricates and protects the working parts.

In addition to preventing the overloading of the wireline the weight indicator will also

show changes in tension due to:

• Fluid levels or changes in fluid density

• Jar action

• Position of downhole equipment.

A different Martin Decker weight indicator is used for 3/16 ins. line because of the higher

pull which can be exerted. The load cell for this instrument has a smaller cross-sectional

area in the diaphragm and is matched to the higher range dial (gauge). The gauge load cell

cannot be interchanged.

Maximum loading(standard) = 2000 lbs (888 DaN)

3/16 ins Unit = 4000 lbs (1777 DaN)

ee) Filling with Hydraulic Fluid

Fluid loss can occur due to leaks or punctured hose etc. and occasionally the system needs

to be refilled.

1) The fluid pump is connected to the filling port at the gauge manifold and the bleed

off screw in the load cell loosened.

2) With the pump chamber full of hydraulic fluid and the hose laid out fully, the pump

is slowly stroked pumping the fluid into the system.

3) Check the bleed off port for returns and if there is any air in the system. Keep load

cell higher than gauge to allow any air in the system to rise and escape through bleed

off port.

4) Pump until the returns have no air and tighten up the bleed screw.

5) Pump some more fluid to get a one inch load gap.

6) Open the bleed screw and bleed back the load gap to 3/8 ins if using 50' of hose (1/2

ins if using 100' of hose).

7) Remove the pump and install the filler plug.

8) Check the correct reading of the gauge against a tensiometer or another weight

indicator.

CAUTION: Do not crush or cut the hose.

NOTE: Before picking up any weight across the load cell, the indicator should be

reset to zero.

7.4 MEASURING WHEEL

The purpose of the measuring wheel is to indicate accurately the length of wire passing

through it. It is set to zero with the tool at the wellhead, and therefore measures the depth of

the tool in the well.

The main component of the counter is an accurately machined grooved sheave around

which the wireline is normally wrapped once. Contact of the wireline with this measuring

wheel is maintained by the tension in the wireline and by two adjustable pressure wheels

machined to fit into the groove of the measuring wheel. The wheel is attached, either

directly to the axis of a digital meter (odometer) or by means of a flexible drive, permitting

location of the meter on the panel inside the cabin of the wireline unit.

For braided lines, straight line type measuring devices, such as those manufactured by

Mathey, Bowen, Gearhardt Owen and Otis are utilised. Alternatively, the measuring wheel

on the Halliburton type head can be changed and the 3/16 ins line run straight through the

head and not wrapped around the wheel.

Care should be taken to ensure that the correct path for the line round the measuring wheels

is selected to avoid reverse bending the wire.

The measuring device is normally mounted on moveable supports so that it can move

laterally, guided by the operator as the wire is spooled onto or from the drum. This is

controlled with a handwheel inside the cab through a spindle and chain arrangement.

A measuring wheel exists for each wire diameter and may be calibrated in feet or meters.

When changing the diameters of wire it is only necessary to change the wheel and pressure

wheels which are supplied in matched sets.

Prior to threading the wire through the counter, check that the counter wheel is free to

rotate and that the odometer is recording - this is especially important when there is a

flexible connection to the odometer in cab. Also check for wear in the counter rim and

pressure wheels.

Quick check for depth meter (counter): 8" wheel - 2 ft = 1 revolution

16" wheel - 4 ft = 1 revolution

Figure 7.3 – Halliburton ‘K’ Measuring Wheel

7.5 CAUSES FOR DEPTH DISCREPANCIES

There are many factors that can limit the linear accuracy of slickline measurement in the

tubing bore. With conventional measuring devices, the primary factors that affect true

measurement of a slickline are elastic stretch, temperature, buoyancy, drag, lift, and out-of-

tolerance measuring wheels. To further complicate matters, slickline varies in size and

material. The most commonly used slicklines are .092-, .108-, and .125-inch diameter

wires. The materials range from mild steel to alloy steels.

Elastic stretch for a slickline is a function of line tension and the modulus of elasticity of

the wire. The elastic stretch coefficients for the various wire sizes can usually be obtained

from the wire manufacturer but are, at best, an average; testing can reveal more accurate

coefficients. It is important to understand that line tension is not incorporated into the

depth measurements in conventional slickline measuring systems. Line tension is

measured using a hydraulic-type load sensor instead of an electronic strain gauge. The

hydraulic-type load sensors are calibrated to specific rig-up angles, usually 90 degrees,

since the load cell is placed in the lower sheave and will give inaccurate line tensions if the

included rig-up angle does not match the calibration.

Length measurements may be increased by out of tolerance measuring wheel diameters

resulting from wear or decreased because of debris build-up on the wheel surface. Changes

in measuring wheel diameters can result from large variations in ambient temperature

between the temperature at which the measuring wheel was manufactured or calibrated and

the temperature at which it operates. Temperature differences also affect wire length as it

is lowered into the well. Unless wellbore temperature/measurement variations are input

into depth corrections, this cause of variation is difficult to adjust.

The last factors affecting true wire length or tool depth are buoyancy and drag or lift, which

are a function of fluid viscosity, wellbore geometry, flowing conditions of the well, line

speed, etc. For all practical purposes, these factors are inherently measured as tension on

the surface. Extensive testing to determine compensation for wire-measurement changes or

dynamic tool depth because of these factors would be impractical for slickline applications

at this time.

Although these factors may not result in significant changes at shallow depths, they can

produce large discrepancies at deeper depths. Elastic stretch for .108-inch wire suspended

in a column of water accounts for the largest change in wire length at 12.5 feet in 10,000

feet. The temperature affects to the wire and measuring wheel were based on a 50°F

change at 50°F temperature change can result in a 3.92 ft change in 10,000 feet. The lack

of tolerance on the 4 foot circumference measuring wheel was based on a .001-inch change

to the measuring diameter, which caused a 0.65 foot change in 10,000 feet.

The load cell angle adjustment was shown to illustrate the change in depth if tension was

input incorrectly.

The 15° change in the included rig-up angle resulted in a 11/2 foot change in 10,000 feet. A

combination of any of these factors can create even greater linear inaccuracy.

7.5.1 Wireline Angle Correction Factors

The load registered on the weight indicator of the wireline unit does not indicate the total

load exerted on the line.

If the angle between the wireline entering and exiting the hay pulley is 90° then the reading

on the weight indicator is correct; see Figure 7.4. If the angle between the wireline

entering and exiting the hay pulley is less than 90° then the reading on the weight indicator

is higher than the actual load on the line. Refer to example 1.

If the angle between the line entering and exiting the hay pulley is more than 90 then the

reading on the weight indicator is lower than the actual load on the line. Example 2

Using the tables provided, the actual (resultant) load on the line can be calculated prior to

wireline operations. (Refer to examples 1 and 2)

Figure 7.4 - Martin Decker Weight Indicator 27

Example 1

Angle below 90O then WT indicator dial

reads higher than actual resultant.

e.g. Angle between entry and exit line =

70O

WT indicator reads 1000 lbs.

= 1000 ÷ 1.63830 (constant for 70O

from Table 7.1) x 1.41422 (constant for

90O from Table 7.1)

= 1000 ÷ 1.63830

= 610.3888 x 1.41422

= 863 lbs at 70O

Angle above 90O then weight indicator

dial reads lower than actual resultant.

Example 2

e.g. Angle between entry and exit line =

110O

WT indicator reads 811 lbs.

= 811 ÷ 1.14716 (constant for 110o

from Table 7.1) x 1.41422 (constant for

90O from Table 7.1)

= 811 lbs ÷ 1.14716

= 706.963. x 1.41422 = WT indicator

reads 811 lbs when resultant is 1000 lbs at

110O

Figure 7.5 – Examples

To interpolate odd number angles not shown on the following chart calculate according to

above formulae the resultant of the angle one degree less and one degree more than the

angle desired and split the difference. (Figures provided by Martin Decker, Aberdeen).

Included

Angle Of

Line

Load

By

Constant

Resultant Included

Angle Of

Line

Load

By

Constant

Resultant

0 2.00000 92 1.38932 2 1.99970 94 1.36400 4 1.99878 96 1.33826 6 Multiply 1.99726 98 Multiply 1.31212 To Get 8 Line 1.99512 To Get 100 Line 1.28558 Resultant 10 Load 1.99238 Resultant 102 Load 1.25864 12 By 1.98904 104 By 1.23132 14 1.98510 106 1.20362 16 1.98054 108 1.17556 18 1.97538 110 1.14716 20 1.96962 112 1.11838 22 1.96326 114 1.08928 24 1.95630 116 1.05984 26 1.94874 118 1.03008 28 1.94058 120 1.00000 30 1.93186 122 0.96962 32 1.92252 124 0.93894

34 1.91260 126 0.90798

36 1.90212 128 0.87674 38 Multiply 1.89104 130 Multiply 0.84524 40 Line 1.87938 To Get 132 Line 0.81348 To Get 42 Load 1.86716 Resultant 134 Load 0.78146 Resultant 44 By 1.85436 136 By 0.74922 46 1.84100 138 0.71674 48 1.82708 140 0.68404 50 1.81262 142 0.65114 52 1.79758 144 0.61804 54 1.78202 146 0.58474 56 1.76590 148 0.55128 58 1.74924 150 0.51764 60 1.73206 152 0.48384 62 1.71434 154 0.44990 64 1.69610 156 0.41582 66 1.67734 158 0.38162 68 1.65808 160 0.34730 70 1.63830 162 0.31286 72 1.61804 164 0.27834 74 1.59726 166 0.24374 76 Multiply 1.57602 168 Multiply 0.20906 78 Line 1.55430 To Get 170 Line 0.17430 To Get 80 Load 1.53208 Resultant 172 Load 0.13952 Resultant 82 By 1.50942 174 By 0.10468 84 1.48626 176 0.06980 86 1.46270 178 0.03490 88 1.43868 180 0.00000 90 1.41422

Table 7.1 – Wireline Angle Correction Factors

7.6 WIRELINE CLAMP

The clamp is used to hold the wire while raising or lowering the lubricator and can be

utilised during fishing operations.

Clamps must be kept clean and dry to allow maximum grip on the wire.

The clamp is employed when it is necessary to clamp the wire and to hold the toolstring in

position, the tension from the unit to be slackened off during rigging up/down or on

operations where the tools are to be left in the well. It is also used in fishing operations to

engage a wireline which has parted above the BOP or stuffing box.

The clamp has grooves in the clamping jaws which grip the wire without crushing it,

assisted by a spring. It is usually attached to the lubricator by a clamp which is bolted

around the base of the bottom section of lubricator.

Care must be taken when placing the clamp on the line not to kink the wire. This can result

in a weak point or cause the line to stick in the stuffing box.

Figure 7.6 - Wireline Clamp

8 POWER PACKS

8.1 ELECTRICAL

The power pack discussed in this section is the Zone 1, 75 HP, electric/hydraulic type. This

power pack is an all steel construction skid mounted unit with detachable crash frame. Four

lifting points are provided with a safe working load of 2 tons. The heavy duty frame is

fitted with removable protection side panels for easy access and maintenance.

Most operators use diesel power packs but electrical power packs are used in some areas.

Electrical power packs are required to be intrinsically safe (i.e. spark-proof) and can be

used in Zone 1 operations. Zone 1 is an area around the wellhead which is restricted to

intrinsically safe equipment.

Electrical power packs are simple to operate and maintain. However, care must be taken to

ensure that the power pack is connected to the correct power source. When the power pack

has been connected, the direction in which the motor is running must be checked.

Little maintenance is required on electrical power packs. The hydraulic oil and the suction

strainer must be checked regularly.

Operation and Maintenance

Electric power packs are very simple to operate. However, care must be taken to ensure

that the power pack is connected to the correct power source. When the power pack has

been connected, the direction in which the motor is running must be checked.

NOTE: Before starting the electric pump, the hydraulic system must be looped or

connected to the wireline unit.

ZONE 0 In which a flammable atmosphere is continuously present, or present for long

periods (more than 1,000 hrs per year).

ZONE 1 In which a flammable atmosphere is likely to occur in normal operation (about 10

to 1000 hrs per year).

ZONE 2 In which a flammable atmosphere is not likely to occur in normal operation and if

it occurs it will exist only for a short period (less than 10 hrs per year).

Table 8.1

NOTE: The power pack shall be positioned and only operated in areas

designated as safe, in accordance with IP “model code of safe practice in

the petroleum industry”.

Figure 8.1- Electrical Power Pack

8.2 DIESEL POWER PACKS

Diesel engines are used because they are reliable. They can be made to function more

safely in hydrocarbon hazardous areas (no spark plugs, contact breakers, distributors etc.)

and the exhaust can be fitted with an efficient spark arrestor. Also diesel fuel is widely

available offshore, whereas petrol is normally not allowed. In the unlikely event of engine

problems, the following fault finding tree should lead you quickly to the fault. Diesels are

simple, they require only fuel and compression to operate.

Figure 8.2 - Diesel Power Pack

All units have safety systems fitted to the diesel engines which limits surface temperature

to below 200°C. (In the event of high exhaust or water temperature, automatic shutdown

will occur.) Overspeed shutdown is also used to prevent over-revving. The engines also

breathe through a special flame trap.

8.2.1 FAULT FINDING CHART

Fault Possible Cause

Low crank speed 1,2,3,4

Will not start 5,6,7,8,9,10,12,13,14,15,16,17,18,19,20,22,31,32,33

Difficult starting 5,7,8,9,10,11,12,13,14,15,16,18,19,20,21,22,24,29,31,32,33

Lack of power 8,9,10,11,12,13,14,18,19,20,21,22,23,24,25,26,27,31,32,33,60

Misfiring 8,9,10,12,13,14,16,18,19,20,25,26,28,29,30,32

Excessive fuel consumption 11,13,14,16,18,19,20,22,23,24,25,27,28,29,31,32,33,60

Black exhaust 11,13,14,16,18,19,20,22,24,25,27,28,29,31,32,33

Blue/white exhaust 4,16,18,19,20,25,27,31,33,34,35,45,56

Low oil pressure 4,36,37,38,39,40,42,43,44,58

Knocking 9,14,16,18,19,22,26,28,29,31,33,35,36,45,46,59

Erratic running 7,8,9,10,11,12,13,14,16,20,21,23,26,28,29,30,33,35,45,59

Vibration 13,14,20,23,25,26,29,30,33,45,47,48,49

High oil pressure 4,38,41

Overheating 11,13,14,16,18,19,24,25,45,50,51,52,53,54,57

Excessive crank case pressure 25,31,33,34,45,55

Poor compression 11,19,25,28,29,31,32,33,34,46,59

Starts and stops 10,11,12

Key To Fault Finding

9 WELL CONTROL AND B.O.P. PUMPS

9.1 SINGLE WELL CONTROL PANEL

When conducting well servicing operations in a well, it is a necessary safety precaution to

lock out any pneumatically or hydraulically activated valves and isolate them from the

platform control system.

This has meant the introduction of a mobile well control panel which effectively duplicates

the platform failsafe control system functionally for an individual well, but it is operated

manually. The well control panel is also provided with an emergency shutdown system,

enabling the UMV and DHSV to be closed instantly in an emergency situation.

An overview of the panel is given in Figure 9.1. It consists essentially of a control panel

section comprising of two reservoirs which feed three pneumatically operated Haskel

pumps. These provide a high pressure hydraulic supply for three functions:

1) UMV control – direct hydraulic (fluid depending on location).

2) DHSV control – direct hydraulic (fluid depending on location).

3) Wireline BOP stuffing box control – direct hydraulic (hydraulic oil).

A separate hand pump system is incorporate to enable the operation of a hydraulic stuffing

box system test line.

An additional facility is provided to allow the hook-up of an independent inhibitor supply

using the spare hose and reel.

The hydraulic supply hoses are wound onto four reels mounted beneath the control panel

section.

The low air supply/hydraulic pressure warning system is incorporated into the panel. The

warning system monitors DHSV pressure, UMV pressure and the air supply pressure. If

any of the aforementioned pressures fall below a pre-set level, an air horn sounds to warn

the operator, air supply should be taken from plant air not rig air as this can be lost at times,

such as water injection shut-down.

9.2 OPERATING PROCEDURES

9.2.1 Pre-Operational Function Checks

The functional checks prior to the operation of the panel are detailed below:

1) Locate the panel remotely from the wellhead in such a position that it may be

operated quickly and easily in an emergency, without compromising any route of

escape from the area. Recommended positions are:

• Beside the wireline winch unit, for operation on the skid deck.

• At bottom of Vee Door, for operations using rig.

2) Connect a dedicated air supply to the panel from plant air only.

3) Before connecting the panel hoses to the wellhead and BOP’s, the following function

checks should be performed.

• Pressure test the open and close BOP lines to 3,000psig.

• Pressurise the accumulative system, then close the accumulator valve. Utilising

the enclosed pressure, check for leaks.

• Check that the emergency shutdown (ESD) facility instantaneously dumps both

UMV and DHSV pressures. Reset by closing the ESD valve.

• Pressure test the stuffing box line to a maximum working pressure of

5,000psig.

• Check that the alarm air tank is sufficiently charged (>1,000psi) and function

test the alarm system on each of its separate operating criteria i.e. loss of air

supply. DHSV supply pressure decreasing and UMV supply pressure

decreasing.

• Check that the hydraulic fluid reservoir is filled above the minimum level.

4) Ensure that operations have disconnected the hard piping to the UMV. Make up

Parker Hannifan (or similar) connection to the open port on the actuator body and

connect up the UMV control hose to the actuator.

5) Ensure that operations have isolated the DHSV and main control panel from the

DHSV manifold on the tree flange. Make up Parker Hannifan (or similar) fitting to

this manifold and connect up to the DHSV control hose.

6) Prior to rig-up connect up to the BOP hoses and function test the rams by closing and

re-opening once.

NOTE: The open and close functions on the BOP should have male and female

quick-connect coupling halves respectfully, to prevent connection of the

functions the wrong way round.

9.2.2 Routine Operating Procedures

Throughout this part of the job the well will be under the control of the well service

supervisor who will operate or delegate operation of the panel as required. However, all

wireline personnel should be familiar with its operation, particularly its use in an

emergency situation.

During the entire period when the UMV and the DHSV are locked out from the platform

control system, two persons fully conversant with the operation of the panel must be

available at the wellsite.

The panel should be operated in accordance with the procedures detailed below:

1) As soon as the well has been handed over and prior to pressure control equipment

rig-up the Well Services Supervisor should take control of the well as follows:

• Remove the burst disc fitting from the actuator assembly (180° from control

pressure outlet) and insert 3/8in. NPT plug.

• Switch on the alarm system whenever a valve is open.

2) Once the pressure control equipment has been rigged and the BOP hoses connected

up to the BOP, turn the BOP control lever to the off (block) position. Turn on the

BOP pump and adjust the discharge pressure against this closed valve to suit the BOP

in use. No pressure will be applied to the BOP until the lever is switched to either the

open or the closed position.

3) During the wireline job, both UMV and DHSV pumps should be left in the on

position with the pressure regulated to maintain the operating pressures as specified

by the manufacturer. Regularly monitor for loss of pressure and pump stroking

4) The BOP pump should also be left in the on position, with the BOP operating

pressure preset using the pump regulator. The BOP control lever should be left in the

off position during normal operations.

5) If air supply pressure is lost, the pumps may be operated by hand levers, if required

to maintain pressure.

6) On completion of the job, control of the well should be returned to the platform

control system, with the DHSV left in the open position. The operations shift

supervisor should be informed via the CCR that the well has reverted to platform

control through the handover certificate system.

Figure 9.1 – Well Control Panel

Figure 9.2 – Well Control Panel Unit

10 GENERAL TOOLSTRING

The "Tool-string" is the name given to

any assembly of equipment run in the

well to perform some type of operation.

In wireline work, the string is run,

manipulated and retrieved by the

upward or downward movement of the

wire which is itself raised and lowered

by a winch at the surface.

The tool-string is made up of a number

of basic components with various other

service tools attached according to the

type of operation undertaken.

There are many different operations

and many different conditions to be

satisfied in each operation, so that the

number and type of service tools

available is very large, although some

tools are used far more frequently than

others. The precise configuration of

tool-string will be contingent on factors

such as job type, access, hole deviation,

depth, pressure, completion type, log

history and so on.

Figure 10.1 - Wireline Toolstring

10.1 PRIMARY EQUIPMENT

10.1.1 Rope Sockets

The rope socket provides the means of attaching the wireline to the tool-string.

Pear Drop Socket

For 0.108 ins. and 0.125 ins. wireline the most commonly used rope socket is the pear drop

socket. This socket is easy to make up and little experience is necessary to "tie the knot"

reliably.

The principle of operation is that the wire, wrapped round a groove in the pear drop, is

wedged in a taper between the pear drop and the mating sleeve. This wedge action grips the

wire and is proportional to the tension applied to the wireline.

The benefits of this type of rope socket are that there are no sharp bends in the wire which

reduces its ultimate tensile strength, and is a simple and quick way to make the connection

to the wire.

Figure 10.2 - Pear Drop Type Rope Socket

10.1.2 Wireline Stem

Wireline stem or "sinker bar" is required as part of the wireline tool-string to increase the

weight.

A "rule of thumb" to determine the weight of solid steel stem is:

OD2 x 8/3 = Wt of stem in lb/ft.

Increase of stem weight increases the impact force delivered by the jars. The tool-string

should not be over-weighted as excessive mass dampens the "feel" and premature shearing

of shear pins can occur.

Flats for wrenches are provided and should be used. Do not grip the tool on the fishing

neck as this may damage the fishing neck shoulder.

All connections should be clean and dry. Do not lubricate tool-string threads as they could

unscrew downhole with extended periods of jarring.

The threads found on wireline tools are known as “sucker rod” thread. The three most

common sizes of thread are as follows.

• 15/16”

• 1 1/16”

• 1 9/16”

These sizes should be committed to memory.

Threads should be checked before rig up and after use. "Flaring" can occur on sinker bar

threads. This is indicated by the peaks of one or more threads being angled upwards rather

than at right angles to the stem. It is probably caused by a piece of stem being continually

used for heavy jarring. "Flared" threads do not grip uniformly with good/bad threads and

can back off very easily. Therefore, any pieces of stem with "flared" threads should be

replaced immediately.

The table below is a selection of some of the most common stem sizes and lengths that can

be used.

Size Thread Size Fishneck OD Max OD Length

1 ½” (1.5 in.) 15/16” Sucker Rod 1.375” 1.5” 2ft, 3ft, 5ft

1 7/8” (1.875 in.) 1 1/16” Sucker Rod 1.75” 1.875” 2ft, 3ft, 5ft

2 1/8” (2.125 in.) 1 1/16” Sucker Rod 1.75” 2.125” 2ft, 3ft, 5ft

2 ½” (2.5 in.) 1 9/16” Sucker Rod 2.313” 2.5” 2ft, 3ft, 5ft

1 7/8” Roller Stem 1 1/16” Sucker Rod 1.75” 2.125” Rollers 2ft, 3ft, 5ft

2 1/8” Roller Stem 1 1/16” Sucker Rod 1.75” 2.5” Rollers 2ft, 3ft, 5ft

2 ½” Roller Stem 1 9/16” Sucker Rod 2.313” 3.125” Rollers 2ft, 3ft, 5ft

Table 10.1

Figure 10.3 - Threaded Connections

10.1.3 Lead Stem

To provide greater weight for the same diameter and length lead-filled stems are available.

This stem has regular steel pin and box connections and a tubular steel outer barrel. The

inside is filled with lead to provide greater weight.

This stem is used primarily to run flow pressure and temperature survey tools to obtain

maximum weight with minimum cross-sectional area to protect against "floating" or being

blown up the hole by pressure surges.

Other high density, heavy weight stem which is available, includes: tungsten, uranium and

mallory (mercury alloy) filled stem.

DO NOT USE lead-filled stem for jarring as the lead will tend to creep downwards and

split the outer barrel.

Figure 10.4 - Lead Stem

10.1.4 Roller Stem

Roller Stem is used for work on deviated wells, or in wells with paraffin, asphaltine, etc. on

the tubing internal walls. It allows the stem to roll down the tubing wall, hence, cutting

down friction incurred when using regular stem.

NOTE: Nylon or Teflon rollers should be used in chrome and/or plastic coated tubing

(refer to Expro Operational Guidelines).

CAUTION: Rollers and axles should be inspected for wear before use. Tools to be run should have a larger OD than the roller stem.

Figure 10.5 - Roller Stem

10.1.5 Jars

Jars are a principal component normally included in every toolstring. Their purpose is to

act as a downhole hammer and provide impact force to operate, set and retrieve downhole

equipment. Wireline alone cannot impart sufficient force due to its low breaking strength

and wellbore friction. Wireline is only used to convey and position the toolstring in the

wellbore.

Jars are activated by hand or winch movement of the wireline and it is essential that the

operator can recognise the precise opening and closing point of the jars on the wireline unit

weight indicator. If the jars are not being operated correctly or if the jar action is lost then

very little force can be exerted on the tools.

There are two main types of jar – Mechanical and Power

The normal mechanical jar is

• Spang jars (Long Stroke = 30” – Short Stroke 20”)

• Tubular jars

which have a mechanical action, and

• Spring jars

• Hydraulic Jars

which are upstroke jars only.

From the formula,

F = ma (Force = Mass x Acceleration)

it can be seen that increasing the impact force can be achieved by increasing the:

• Stem weight (Mass)

• Speed at impact (Acceleration/Kinetic Energy, Mechanical Jars only).

Jars would not normally be run in toolstrings that contain devices liable to damage by their

action, eg. pressure and temperature gauges, flowmeters, etc.

ff) Spang Jars

Spang Jars; See Figure 10.6, are the most commonly used as they are mechanically simple,

require little maintenance and can be used to jar both up or down.

However, well debris can interfere with this action and their open construction could

possibly allow any wireline being fished to become entangled.

Jarring force in both directions is governed by stem weight and wire speed and to a lesser

extent by stroke length. However, the efficiency of jarring down is restricted by the

viscosity of the well fluid, the well deviation and the friction of the wire at the Stuffing

Box.

In deeper wells, long stroke jars can help give a more pronounced opening and closing

indication at surface. However, long stroke jars in large bore wells are prone to ‘scissoring’

caused by jarring down. In small bore tubing, the tubing walls prevent excessive buckling.

However, in large bore tubing, the elastic limit of the jar body may be exceeded, causing

permanent buckling and misalignment (‘scissoring’) of the upper and lower body parts.

Figure 10.6 - Spang Jars

gg) Tubular Jars

Tubular Jars, See Figure 10.7, are commonly used when fishing for wireline or working

below tubing in the sump. Its moving components are for the most part enclosed inside a

housing, protecting it from entanglement with the wireline to be fished and other well

debris.

Tubular jars have screwed components, which are susceptible to backing off during

prolonged jarring. Also, the efficiency of jarring down may be decreased due to the

viscosity effects of the fluid displaced from inside the housing.

Figure 10.7 - Tubular Jars

hh) Spring Jars

Spring Jars, See Figure 10.8, are used in situations where Spang Jars have been, or are

likely to be unsuccessful. This can be, for example, in deviated wells when wire speed is

insufficient or, in general, when more jarring force is required.

Figure 10.8 - Spring Jars

They can be used to jar-up but, because of their construction, it is possible for debris to

enter and make them difficult to reset. They also require regular maintenance. They are

used in gas wells in preference to hydraulic jars since they are not dependent on elastomer

seals (this removes the risk of fluid entry). In general, they are more durable than

Hydraulic Jars as their construction is purely mechanical.

The impact force of spring jars is determined by the selection or adjustment of the spring or

release mechanism. This spring or release mechanism prevents any relative movement of

the two parts of the jar, until a predetermined wire pull is reached. The first section of

relative motion of the two parts is to overcome the spring or release mechanism tension.

This in turn allows the release mechanism to actuate, freeing the inner rod to move

upwards without restriction and induce the jarring action.

If a Spring Jar malfunctions, it is not normally detrimental to the function of the rest of the

toolstring. If unable to release, it acts as a rigid section of toolstring. If unable to close, it

acts as an additional Spang Jar.

ii) Hydraulic Jars

Hydraulic Jars, See Figure 10.9, are used in similar circumstances to spring jars ie. when

spang jars have been unsuccessful, or are likely to be unsuccessful.

The main advantage of the Hydraulic Jar is that the jarring force is adjustable, since it is

determined by the initial pull on the wire. In addition, this type of jar (in common with

spring jars) is more suited to extended jarring operations. This is because the wireline can

be run slower, since the impact force of these jars does not depend on the wire speed which

results in less wear and tear on the wire.

Hydraulic Jars can only be used to jar up and, because their construction includes many

elastomer seals, regular maintenance is required since well fluid and debris can enter the

hydraulic chamber.

In the presence of gas, the hydraulic oil can become contaminated. This alters its volume

and compressibility, reducing the jarring efficiency and can prevent the jar closing. In

addition, a ‘gassed-up’ hydraulic jar can seriously affect the jar-down action of the

mechanical jar in the string. Since the Hydraulic Jar is usually placed between the Stem and

the Mechanical Jar, it acts as a shock absorber, reducing the weight transmitted.

Upward pull on the wire pressurises the oil contained in the upper chamber. The piston is

designed not to form a good seal on the chamber bore and this will allow a slow controlled

flow of oil past it. The piston will travel upwards slowly until it encounters a wider bore

section of the chamber. At this point there is no longer significant resistance to the oil

flowing past the piston which will then move rapidly upwards to produce the jarring action.

To speed up the resetting action (closing), the piston contains a one-way check valve which

opens as the piston moves down.

NOTE: When rigging up or down heavy toolstrings, the hydraulic jars can be

opened under toolstring weight.

NOTE: Both spring and hydraulic jars should be fully closed prior to laying

down the toolstring to avoid bending or damaging the jar rod.

Figure 10.9 - Hydraulic Jars

10.1.6 Stretch Simulators/Accelerators

Stretch Simulators or Accelerators; see Figure 10.10, are installed in the Toolstring

immediately below the rope socket when Spring/Hydraulic Jars are to be used at shallow

depths. The spring replaces the ‘stretch’ of the wireline, which exists when jarring up. It

reduces the shock loading at the Rope Socket and causes the stem to ‘accelerate’ faster

when the Spring/ Hydraulic jars go off. This creates a more effective impact.

The device works by the wireline pulling on the top section while the bottom section is

held by the pulling tool. The internal spring is compressed and as the jar below fires, this

spring expands which in turn accelerates the toolstring giving more impact. This limits the

loading on the wireline. In theory it would be a good practice to use this device all the time

- but it makes the toolstring assembly complicated.

CAUTION: The assembly should be thoroughly checked prior to running, i.e. end-subs tight, proper freedom of movement, spring in good condition.

NOTE: The accelerator must be matched with the correct vendor’s power jar.

Figure 10.10 - Wire Stretch Simulators

10.2 TOOLSTRING ACCESSORIES

There are many types of quick-lock connectors on the market, the following sections

describe the most common.

10.2.1 Quick-Lock System (Petroline)

Quick-Lock systems toolstrings may be used instead of (or in conjunction with) the

threaded type. The Quick Lock System, See Figure 10.11, is built onto the whole range of

toolstring equipment. There is no need for wrenches when making up this system. The

male half is mated to the female half, then rotated 90°. A spring loaded locking slip

engages a slot and locks the assembly in place. To release the locking device it is

mechanically lifted by means of a cut away window in the stem body.

This system is faster and easier to make up than the threaded type. It is stronger and will

not accidentally back off since it does not incorporate threads.

The advantage of using a Quick-Lock connector is that no wrench marks (and hence no

burrs) are induced on equipment (cutting down wear and hand injuries.)

Figure 10.11 - Petroline Quick-Lock System

Figure 10.12 – Trinity Locking System

10.2.2 Trinity Quick-Lock System

The most striking feature of the trinity quicklock is its triangular shape. Like the Petroline

quicklock its easy to make-up and adds strength by evenly distributing load round the

circumference of the connection. In addition to this the connection employs a support

shoulder to absorb side impacts and strengthens the female connection with the support

below the bottom lug. The locking and release mechanism is by way of a trigger mounted

in the female which unlike Petroline quicklock system is operated by hand and does not

require the use of any additional implements to release. It is also available as crossovers or

integral parts of toolstring components.

10.2.3 Knuckle Joints

Knuckle joints are included in the wireline tool-string to offer a degree of lateral flexibility.

They incorporate a ball joint assembly allowing rotation and some angulation.

During wireline operation in deviated wells, lengthy tool-strings without knuckle joints

may be forced to bend during running to follow the angles of the tubing. This causes

friction and up/down mobility can be seriously impaired. They are also used during fishing

operations to give flexibility between fishing tool and jars, and so aid latching.

Extended periods of jarring can damage the knuckle joint hence their use in tool-strings

should be kept to a minimum. The ball joints, threads, and any pins should be thoroughly

inspected prior to use.

Figure 10.13 - Knuckle Joints

11 BASIC PULLING TOOLS

11.1 FISHING NECK IDENTIFICATION / EXTERNAL / INTERNAL /

REACH

Pulling tools are for recovering and, to a lesser extent for running flow control assemblies

and other items of downhole equipment.

All downhole assemblies are equipped with standard fishing necks. To identify the

corresponding pulling tool, only the ID/OD and reach are required.

They are only used if a standard fishing neck is accessible. If not (eg. if a part of the tool

remains downhole) then a special tool (ie. an overshot) has to be used.

The pulling tool must be selected according to the size and type (internal or external) of the

lock mandrel (or other downhole devices) to be retrieved. This means that, at the time the

device is run, its size must be carefully measured and logged.

Pulling tools from different manufactures often have slightly differing detail design. For

this reason, they should be used with fishing necks from the same manufacturers if

possible. In practice, these small differences normally do not affect compatibility.

Figure 11.1 – Fishing Neck Compatibility

Two types of fishing neck exist - internal and external. External fishing necks are used

generally on toolstrings and running and pulling tools.

The advantage of internal fishing necks is that they have larger flow areas and for this

reason are often used with flow control assemblies.

Both downhole assemblies and pulling tools may be set or sheared up or down. Any

combination is possible depending on the operation to be performed and the equipment

itself.

A shear-up pulling tool might be selected in preference if there is a potential difficulty

releasing by shearing down, e.g. debris around fishing neck, or a toolstring in a ball of wire

to be fished which moves down but not up.

A shear-down pulling tool might be selected in preference for extended periods of upward

jarring, to remove the risk of premature shearing off.

The pulling tool is fitted immediately below the spang jar, and the assembled tool is then

run to a depth predetermined by the location of the device to be retrieved. Where

necessary, a knuckle joint can be fitted between the pulling tool and the spang jar to assist

in the latching operation.

Therefore the operator must be able to immediately identify a tool's shear direction.

The shear direction and the outcome of running any pulling tool in the hole must be given

careful consideration at the planning stage of the job.

Tool Type Shear Direction

Otis ‘S' Series Down

Otis ‘R’ Series Up

Camco ‘JD’ Series Down

Camco ‘JU’ Series Up

Otis ‘GS’ Series Down

Otis 'GR’ Series Up

Table 11.1 - Shear Direction Chart

11.1.1 Selection of Shear Direction

It is essential that the operator selects a tool which shears in the direction opposite to which

jarring is required to achieve movement downhole, i.e. if a jar down action is required to

unlock a lock mandrel a jar up to shear tool must be used.

NOTE: In some cases this rule may not apply.

Figure 11.2 - General Operation of ‘SB’ Pulling Tool

11.2 EXTERNAL BASIC PULLING TOOLS

11.2.1 Otis ‘S’ Series Pulling tools (Shear down to release)

The type ‘S’ series of pulling tool is designed to engage with external fishing necks e.g.

rope sockets, stems, equalising prongs, test tools and to shear and release by downward jar

action. Three types of ‘S’ series tools are used and differ only by their core length, which is

selected to give a desired reach:

Type ‘SB’ Long core/short reach

Type ‘SS’ Intermediate core/Intermediate reach

Type ‘SJ’ Short core/long reach

All other parts of the tools are identical and completely interchangeable.

Type ‘SM’ Intermediate core / Intermediate reach. Used mainly to pull gas lift valves.

Figure 11.3 - ‘S’ Core Length and Corresponding Applications

jj) Operational

On reaching the working depth, the weight of the tool-string bears down on the device to

be pulled and, if necessary, is backed up by a light downward jar.

NOTE: Downward jarring at this stage should be kept to a minimum to avoid

premature shearing.

Once latched on, pulling operations can begin.

Due to the design of the tool, the downward force produced by the jarring action is exerted

through the pulling tool cylinder (skirt) and, in turn, through the shear pin. The core must

therefore remain stationary and the cylinder must move downwards in relationship to the

core, in order to shear the pin. The tool cannot be sheared if the cylinder is unable to move

downwards because it is resting on the fish or devices to be released.

A feature of the ‘S’ series pulling tool is its ability to sustain upwards jarring without

releasing. In certain circumstances the tool can be used in running operations.

Another version or type of ‘S’ series pulling tool is the Type ‘SM’. This is a special

purpose tool designed primarily to retrieve certain side pocket gas lift latches. Although it

is a shear down to release tool of similar design to the Types ‘SB’ and ‘SS’, various

dimensions are different and components are not usually interchangeable.

kk) Operational Check

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be redressed before storing.

11.2.2 Otis ‘R’ Series Pulling Tools (Jar up to release)

Figure 11.4 is designed to engage with external fishing necks, e.g. rope sockets, stems,

equalising prongs, test tools and to shear and release by upward jar action. Three types of

‘R’ series tools are used and differ only by their core length; see Figure 11.4, which is

selected to give a desired reach:

• Type ‘RB’ - long core/short reach

• Type ‘RS’ - intermediate core/intermediate reach

• Type ‘RJ’ - short core/long reach.

(All other parts of each type of tool are identical and completely interchangeable.)

On reaching the working depth, the weight of the toolstring bears down on the device to be

pulled and, if necessary, is backed up by light downward jarring.

Once latched, pulling operations can begin.

If the pulling operation is prevented by, for example, the build up of debris, scale or

differential pressure, the shear pin will shear and so unlatch the dogs from the fishing neck.

The pulling tool can now be retrieved, redressed or changed for another type.

NOTE: When jarring up with ‘R’ tools, large forces can be imparted to the shear

pin. For this reason, these tools are generally fitted with larger shear pins

than those fitted to equivalent shear down tools. Despite this, as the shear

pin takes the full load of the force imparted by the jar, it can sometimes

shear before the pulling operation is accomplished.

Two features of the ‘R’ Series pulling tool are its ability to sustain downwards jarring

without releasing and it is not dependent on the core bottoming out to achieve shearing.

In certain circumstances, the tool can be used in running operations.

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be cleaned and redressed before storing.

The ‘R’ Pulling Tool is attached to a standard toolstring and lowered into the well. Upon

contact with the sub-surface device, the lower portion of the cylinder passes over the

fishing neck; the dogs are pushed outward, the force of the dog spring then makes the dogs

spring inward to engage the fish neck. Upward impact of the jars is used to pull the sub-

surface device from the well.

The shear pin should withstand considerable jarring before shearing. When the pin shears,

the cylinder spring acts between the cover and the cylinder and moves the core up in the

cylinder. This moves the dogs upward against the force of the dog spring. As the dogs

move upward, their tapered upper ends move into the cylinder, forcing the dogs inward

thereby pushing the lower ends of the dogs outward. This causes the dogs to release their

grip on the fish neck.

Figure 11.4 - Otis Type ‘R’ Pulling Tool

11.2.3 Camco ‘JD’ Series Pulling Tools (Jar down for release)

The type ‘JD’ series Pulling Tool; see Figure 11.5, is designed to engage with external fish

necks, eg. rope sockets, stems, equalising prongs, test tools and to shear and release by

downward jar action. Three types of ‘JD’ series tools are used and differ only by their core

length, which is selected to give the desired reach:

• Type ‘JDC’ - long core/short reach

• Type ‘JDS’ - intermediate core/intermediate reach

• Type ‘JDL’ - short core/long reach.

(All other parts of each type of tool are identical and completely interchangeable.)

On reaching the working depth, the weight of the toolstring bears down on the device to be

pulled and, if necessary, is backed-up by light downward jarring.

NOTE: Downward jarring at this stage should be kept to a minimum to avoid

premature shearing.

Once latched on, pulling operations can begin.

Due to the design of the tool, the downward force produced by the jarring action is exerted

through the pulling tool cylinder (skirt) and, in turn, through the shear pin. The core must,

therefore, remain stationary and the cylinder must move downward in relation to the core

in order to shear the pin. The tool cannot be sheared if the cylinder is resting on the fish or

device to be released.

A feature of the ‘JD’ pulling tool is its ability to sustain upwards jarring without releasing.

In certain circumstances, the tool can be used in running operations.

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be cleaned and redressed before storing.

Figure 11.5 - Camco Type ‘JD’ Pulling Tool

11.2.4 ‘JU’ Series Pulling Tools (Jar up to release)

The type ‘JU’ Pulling Tool; see Figure 11.6, is designed to engage with external fishing

necks eg. rope sockets, stems, equalising prongs, test tools and to shear and release by

upward jar action. Three types of ‘JU’ Series tools are used and differ only by their core

length which is selected to give a desired reach:

• Type ‘JUC’ - Long core/short reach

• Type ‘JUS’ - Intermediate core/intermediate reach

• Type ‘JUL’ - Short core/long reach.

(All other parts of each type of tool are identical and completely interchangeable.)

On reaching the working depth, the weight of the toolstring bears down on the device to be

pulled and, if necessary, is backed up by light downward jarring.

Once latched on, pulling operations can begin.

If the pulling operation is prevented by, for example, the build up of debris, differential

pressure or scale, the shear pin will shear and so unlatch the dogs from the fishing neck.

The pulling tool can now be retrieved, redressed or changed for another type.

NOTE: When jarring up with ‘JU’ tools, the shear pin takes the full load of the

force imparted by the jar, it can sometimes shear before the pulling

operation is accomplished.

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be redressed before storing.

Figure 11.6 - Camco Type ‘JU’ Pulling Tool

Figure 11.7 – Shear Pins

11.2.5 Otis "GS" Pulling Tool

The type "GS" pulling tool is designed to engage with internal fishing necks e.g. lock

mandrels and to shear and release by downward jar action.

Operation

On reaching the working depth, the weight of the tool-string bears down on the device to

be pulled and if necessary, is backed up by a light downward jar. On locating the device to

be pulled, the dogs of the "GS" automatically engage by their upward movement over the

tapered core. This allows the dogs to retract and enter the recessed pulling neck. Once in

the recess, a spring forces the dogs down over the taper and out into the lock mandrel fish

neck. As the fish neck has a restricted diameter, the dogs are securely locked in the mandrel

and upward jarring can commence.

NOTE: Downward jarring at this stage should be kept to a minimum to avoid

premature shearing.

Due to the design of the tool, the downward force produced by the jarring action, is exerted

through the pulling tool core and in turn through the shear pin. The skirt must, therefore,

remain stationary and the core must move downwards in relation to the skirt in order to

shear the pin. The tool cannot be sheared if the core is resting on debris etc. A feature of

the "GS" pulling tool is its ability to sustain upward jarring without releasing. In certain

circumstances, the tool can be used in running operations when fitted with an appropriate

prong.

Operational Checks

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be redressed before storing. To release the pulling tool from the

lock mandrel; grasp the dog retainer with the thumb and forefinger and force it up to

compress the spring. This should lift the dogs enough to allow them to retract against the

small outside diameter of the core. Remove the mandrel from the pulling tool

Disassembly Procedure

1) Place the "GS" pulling tool in a vice, gripping the flats on either side of the core

bottom.

2) Rotate the shear pin retainer sleeve until the shear pin ends are exposed. Carefully

drive out the shear pin.

NOTE: Bear in mind that the cylinder spring is under compression and will snap

the cylinder back to the fish neck shoulder upon pin removal.

3) Loosen the set screw in the fish neck and remove the fish neck from the core.

4) The remaining cylinder sub assembly can now slide off the upper end of the

core.

NOTE: At this point, the core can be changed without further disassembly of the

tool.

5) Insert the cylinder in a vice and remove the top sub which also retains the shear pin

sleeve.

6) Remove the cylinder spring from the inside of the cylinder top sub.

7) The cylinder spring retainer, dog spring, dog retainer and dog segments may now be

removed from the cylinder body.

Assembly Procedure

Prior to assembly, wash all parts thoroughly and lubricate all threads with good quality

thread lubricant.

1) Place the cylinder horizontally in the jaws of the vice with one window of the

cylinder facing up.

2) Slide the dog retainer through the threaded end of the cylinder and position it in the

dog retainer.

3) Insert one dog through the lower end of the cylinder and position it in the dog

retainer.

4) Reaching through the threaded end of the cylinder, rotate the dog retainer until the

next dog slot appears in the window of the cylinder. Insert the next dog as before, and

continue until all dogs are in place.

5) When all dogs are in place, move the dog retainer and the attached dogs all the way

down into the cylinder.

6) Install the dog spring over the spring retainer, and insert the spring retainer, and

insert the spring retainer (small end first) through the threaded end of the cylinder.

7) Insert the cylinder spring into the area under the threads of the top sub.

8) Make up the top sub and shear pin retainer sleeve into the cylinder and remove it

from the vice.

9) Grasp the flats on the lower end of the core in the vice with the core in the vertical

position.

10) Slide the cylinder assembly down over the core.

11) Make up the fish neck onto the core and tighten the connections.

12) Install the set screw.

13) Before using the tool, install the shear pin.

Re-pinning Procedure (Using "GU" Adapter)

1) Place the "GU" adapter in the vice.

2) Turn the shear pin retainer sleeve on the "GS" to expose the sheared parts of the shear

pin. On some types of "GS" the cylinder will have to be backed off to expose the

shear pin.

3) Turn the "GS" horizontally and using its own weight only, tap lightly on a bench or

vice. This should expel the broken parts of a shear pin;

4) Screw the fishing neck of the "GS" into the "GU" adapter. This action will overcome

the spring tension of the "GS" and align the shear pin holes.

5) Insert the new shear pin (this will drive out the remaining part of old pin) and cut it to

size.

6) Turn the shear pin retainer sleeve 90' to cover the shear pin.

7) Unscrew the "GS" from the "GU" adapter and remove the "GU" adapter from the

vice. (The "GS" is now ready for use).

Figure 11.8 – Otis ‘GS’ Pulling Tool

Figure 11.9 – Otis ‘GU’ Adapter

11.2.6 Otis "GR" Pulling Tool

The type "GR" pulling tool is basically a "GS" pulling tool converted by fitting an adapter

("GU" adapter – discussed later) to release and shear by upward jar action.

Operation

On reaching the working depth, the weight of the tool-string bears down on the device to

be pulled and, if necessary, is backed up by light downward jarring. On locating, the dogs

of the "GR" automatically engage as they move upwards over the tapered core. This allows

the dogs to retract and enter the recessed pulling neck. Once in the recess, a spring forces

the dogs down over the taper and out into the lock mandrel fish neck. As the fishneck has a

restricted diameter, the dogs are securely locked in the mandrel and upward jarring can

commence.

Due to the design of the tool, the upward force produced by the jarring action, is exerted

through the pulling tool skirt and, in turn, through the shear pin. The core must, therefore,

remain stationary and the skirt must move upwards in relationship to the core in order to

shear the pin.

Features of the "GR" tool:

Can sustain downwards jarring without releasing.

Can be sheared when movement of the core is restrained by debris in the lock mandrel i.e.

shearing only requires that the dogs are locked in the fish neck.

Operational Checks

It is recommended that the shear mechanism is tested prior to use. Following recovery from

the well, the tool should be redressed before storing.

Figure 11.10 – Otis ‘GR’ Pulling Tool

"GU" Adapter Assembly Onto "GS" Pulling Tool

(Assuming adapter shear pin is sheared)

1) Carefully drive the shear pin from the "GS" pulling tool, with consideration to the

compressed cylinder spring.

2) Remove the set screw in the core nut of the "GU" adapter via the port in the main

body, after screwing the core nut downwards to expose the set screw. The pin thus

exposed should be removed

3) The "GU" adapter fish neck should then slide off the core nut.

4) The "GU" adapter shear pin retainer band should be rotated, until the holes align with

and expose the shear pin pieces which should be driven out.

5) The adapter core nut should be tightened onto the "GS" pulling tool fish neck thread,

with the "GS" core held firmly in a vice on the flats of the core bottom.

6) The "GU" adapter fish neck should be lowered over the core nut to the adapter fish

neck.

7) The "GU" adapter pin should be installed through the slotted hole in the fish neck and

the socket head set screw installed to retain the pin. This action secures the adapter

core nut to the adapter fish neck.

8) Compress the "GS" tool cylinder spring until the shear pin holes in the adapter fish

neck and core nut align and install a shear pin.

9) Rotate the shear pin retainer band 90' to retain the pin. The retainer band may be

dimpled with a punch if it is a loose fit and then rotated offset.

"GU" Adapter Assembly Onto "GS" Pulling Tool

(Assuming shear pins are unsheared)

1) With "GS" pulling tool gripped in a vice on the flats of the core bottom, screw the

adapter onto the pulling tool fish neck and tighten with wrench.

2) Rotate pulling tool shear pin retainer and check that the shear pin is removed prior to

running the tool.

CAUTION: If a shear pin is left in the "GS" palling tool, as well as the "GU" adapter, shear off in any direction will be impossible resulting in a stack tool

NOTE: A "GU" adapter may be utilised to re-pin a "GS" pulling tool using the

above method in the absence of a spring compressor tool.

11.2.7 Otis "GU" Adapter

As described above in the "GR" pulling tool section, the "GU" adapter has the primary

function of converting a "GS" tool to a "GR" tool. The "GU"/"GS" assembly can then be

used in operations where release by upward jar action is required. Another use for this

adapter, though non-operational, is to assist in re-pinning the "GS" tool after shear. The

adapter, on uniting with the "GS" tool, pushes its skirt down to expose the damaged shear

pin for removal with a punch.

Disassembly Procedure

1) Grip the fish neck in a vice.

2) Rotate band until the shear pin is exposed and drive out the shear pin with a pin

punch.

3) Move the core nut downwards to the full downward travel position until the set screw

is visible through the port in the main body cylinder.

4) Remove the set screw from the port and drive out the pin thus exposed.

5) Remove the core nut.

Assembly Procedure

Assemble in reverse order from disassembly.

FISH NECK SIZES NOMINAL PULLING TOOLS

1 187" 1 1/2" PULLING TOOL

1.375" 2" PULLING TOOL

1.75" 2 1/2" PULLING TOOL

2.313" 3" PULLING TOOL

3.125" 4" PULLING TOOL

Table 11.2

The above table is a selection of fish neck sizes that are most commonly found and the

pulling tools which will latch the corresponding fish neck.

NOTE: Fishing neck profiles should never be used for breaking tools. Inspect

fishing neck profiles for burrs and wrench damage. While it is

inconceivable that wireline tools and equipment could be used without

sustaining some wear and/or damage, it is inexcusable to carry on using

them in a badly worn or damaged state.

11.2.8 Shear Stock Sizes/Shear Pins

The following chart is a guide to the most common shear stock sizes used in the North Sea

today. However some wireline tools use shear screws rather than conventional shear stock.

SHEAR STOCK SIZES

3/16"

1/4"

5/16"

3/8"

As a general rule the following should be remembered:

• Brass shear stock for setting or light jar action.

• Steel shear stock for pulling or heavy jar action.

This may not always apply and should only be used as a guide.

12 BASIC WIRELINE TOOLS

12.1 GAUGE CUTTER

It is good wireline practice to run a gauge cutter or similar drift before starting any

operation in a well, to check tubing ID and to tag the total depth, to locate the nipple ID

and No-Go's, to cut sand, scale, paraffin and other deposits from the tubing wall. It is also

used to determine the profile of a bridge by running successively smaller cutters and

plotting depth versus sizes to establish the shape of restriction.

ll) Advantages

This tool has no moving parts, has a maintenance free sharp cutting edge requiring little

attention and, incorporates a fish neck.

mm) Disadvantages

If smaller gauge rings are used in large casing/tubing ID's when attempting to clear

restrictions, scale/sand debris can fall on top of tool-string and affect the jar action.

Gauge cutters have no shear off facility.

Figure 12.1 - Gauge Cutter

12.2 LEAD IMPRESSION BLOCK

The lead impression block is filled with lead which extends below the bottom edge. The

lead is held in position by a roll pin or a hex-headed bolt. Either of these are installed prior

to pouring molten lead inside.

nn) Advantages

Lead impression blocks are used to obtain an image of a wide range of equipment

downhole to be latched or fished, e.g. rope sockets (with or without wire), prongs, lock

mandrels and parted tubing.

They have no moving parts and incorporate a fishing facility.

oo) Disadvantages

Lead impression blocks have no shear-off facility.

A false or double impression can occur at obstructions while running in hole (RIH) prior to

reaching the obstruction/tool to be fished, causing difficulty when interpreting the image

obtained.

Use one single downward stroke to make the impression.

Figure 12.2 - Lead Impression Block

12.3 BLIND BOX

The blind box is used when heavy downward jarring is required to dislodge a fish or push a

tool down the hole. It is flat on the bottom and hardened to reduce wear and damage.

pp) Advantages

Blind boxes are available in a wide range of sizes and incorporate a fishing facility. They

require little maintenance as they have no moving parts.

qq) Disadvantages

Blind boxes do not have a shear off facility and they can become entangled with wireline

when fishing and can damage the restriction to be jarred on.

Figure 12.3 - Blind Box

12.4 TUBING END LOCATOR

Tubing end locators are used to locate the end of the tubing when running the completion

as a cross reference check of the tubing tally. They are used also to correlate hold up depth

(HUD), or plugged back total depth (PBTD) accurately from the bottom of the tubing, the

depth of which is known from completion records.

WARNING: The tubing end locator body, finger length and minimum ID of the tubing end needs to be checked to match the size of the tubing end in which it is to be run. Also if there is a mis-run the finger may need to be sheared to get back out of the well. (see Figure 12.4).

Figure 12.4 - Tubing End Locator

rr) Advantages

Tubing end locators are also used to correlate pressure/temperature gauges, etc. and may

eliminate the use of more expensive correlating equipment.

They are available in a range of sizes, incorporate a fishing facility, and are quick and easy

to maintain.

ss) Disadvantages

During pressure testing the tool-string position must be known and monitored as an

increase in pressure can move the tubing end locator up-hole hence shearing the pin.

Care must be taken when loading the tubing end locator into the lubricator to prevent

premature tripping.

When the tool is run and passes out of the tubing the spring loaded "finger" trips out to the

horizontal position. When pulled back, the bottom of the tubing is indicated by overpull.

After this has been done, a further quick pull into the tubing shears a brass pin and allows

the "finger" to collapse against the tool body, permitting the toolstring to be retrieved.

CAUTION: A gauge run is recommended before running the tubing end locator to ensure that it will pass through the tubing. otherwise, a missrun would entail pulling the tool with the "finger" in the running position, which could lead to damage to the tubulars where the "finger" made contact with them. when this happens the pivot pin will shear, dropping the "finger" and spring downhole.

PSL Energy Services 2006

PSL Energy Services 2006